Buckeye Partners (BPL) 10-Q 3 Nov 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Oct. 27, 2017
Document and Entity Information
Entity Registrant Name	BUCKEYE PARTNERS, L.P.
Entity Central Index Key	805,022
Document Type	10-Q
Document Period End Date	Sep. 30, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		146,643,955
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q3

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenue:
Product sales	$ 517,461	$ 337,092	$ 1,482,686	$ 1,086,180
Transportation, storage and other services	405,158	429,513	1,219,407	1,238,141
Total revenue	922,619	766,605	2,702,093	2,324,321
Costs and expenses:
Cost of product sales	506,780	326,718	1,447,408	1,049,315
Operating expenses	157,820	149,867	482,008	446,671
Depreciation and amortization	65,661	63,472	195,987	188,220
General and administrative	23,904	20,321	69,987	63,737
Other, net	501	0	(3,921)	0
Total costs and expenses	754,666	560,378	2,191,469	1,747,943
Operating income	167,953	206,227	510,624	576,378
Other income (expense):
Earnings from equity investments	9,232	2,901	22,710	8,459
Interest and debt expense	(56,561)	(48,476)	(168,870)	(144,093)
Other income (expense)	48	(74)	157	(102)
Total other expense, net	(47,281)	(45,649)	(146,003)	(135,736)
Income before taxes	120,672	160,578	364,621	440,642
Income tax expense	(448)	(308)	(1,709)	(896)
Net income	120,224	160,270	362,912	439,746
Less: Net income attributable to noncontrolling interests	(4,037)	(3,896)	(10,427)	(11,803)
Net income attributable to Buckeye Partners, L.P.	$ 116,187	$ 156,374	$ 352,485	$ 427,943
Earnings per unit attributable to Buckeye Partners, L.P.:
Basic (in dollars per share)	$ 0.82	$ 1.19	$ 2.50	$ 3.28
Diluted (in dollars per share)	$ 0.81	$ 1.19	$ 2.49	$ 3.26
Weighted average units outstanding:
Basic (in shares)	142,088	131,113	141,104	130,439
Diluted (in shares)	142,818	131,940	141,781	131,076

CONDENSED CONSOLIDATED STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Net income	$ 120,224	$ 160,270	$ 362,912	$ 439,746
Other comprehensive income:
Unrealized (losses) gains on derivative instruments	(5,764)	1,052	(11,995)	1,052
Reclassification of derivative losses to net income	3,038	3,037	9,113	7,846
Recognition of costs related to benefit plans to net income	50	252	66	756
Other comprehensive income from equity method investments	11,933	0	39,679	0
Total other comprehensive income	9,257	4,341	36,863	9,654
Comprehensive income	129,481	164,611	399,775	449,400
Less: Comprehensive income attributable to noncontrolling interests	(4,037)	(3,896)	(10,427)	(11,803)
Comprehensive income attributable to Buckeye Partners, L.P.	$ 125,444	$ 160,715	$ 389,348	$ 437,597

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 7,922	$ 640,340
Accounts receivable, net	210,476	236,416
Construction and pipeline relocation receivables	15,082	17,276
Inventories	233,413	356,803
Derivative assets	50,884	1,526
Prepaid and other current assets	40,553	66,536
Total current assets	558,330	1,318,897
Property, plant and equipment	7,806,102	7,523,774
Less: Accumulated depreciation	(1,172,872)	(1,040,492)
Property, plant and equipment, net	6,633,230	6,483,282
Equity investments	1,495,952	89,564
Goodwill	1,004,545	1,004,545
Intangible assets	616,286	616,286
Less: Accumulated amortization	(242,678)	(192,983)
Intangible assets, net	373,608	423,303
Other non-current assets	46,835	101,512
Total assets	10,112,500	9,421,103
Current liabilities:
Line of credit	185,410	0
Accounts payable	82,412	107,383
Derivative liabilities	3,568	26,272
Accrued and other current liabilities	237,884	265,893
Total current liabilities	509,274	399,548
Long-term debt	4,593,635	4,217,695
Other non-current liabilities	96,566	105,437
Total liabilities	5,199,475	4,722,680
Commitments and contingent liabilities (Note 3)	0	0
Buckeye Partners, L.P. capital:
Limited Partners (146,641,503 and 140,263,787 units outstanding as of September 30, 2017 and December 31, 2016, respectively)	4,619,262	4,437,316
Accumulated other comprehensive income (loss)	11,270	(25,593)
Total Buckeye Partners, L.P. capital	4,630,532	4,411,723
Noncontrolling interests	282,493	286,700
Total partners’ capital	4,913,025	4,698,423
Total liabilities and partners’ capital	$ 10,112,500	$ 9,421,103

CONDENSED CONSOLIDATED BALANCE5

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Sep. 30, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Limited Partners, units outstanding	146,641,503	140,263,787

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash flows from operating activities:
Net income	$ 362,912	$ 439,746
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	195,987	188,220
Amortization of debt issuance costs and discount	3,940	3,532
Amortization of losses on terminated interest rate swaps	9,113	9,112
Non-cash unit-based compensation expense	25,935	22,977
Gains on property damage recoveries	(4,621)	(5,700)
Net changes in fair value of derivatives	(25,421)	98,917
Amortization of unfavorable storage contracts	0	(5,979)
Earnings from equity investments	(22,710)	(8,459)
Distributions of earnings from equity investments	25,902	2,418
Other non-cash items	1,024	3,772
Change in assets and liabilities, net of amounts related to acquisitions:
Accounts receivable	25,548	(40,109)
Construction and pipeline relocation receivables	2,109	(4,334)
Inventories	123,390	(101,016)
Prepaid and other current assets	18,956	(45,841)
Accounts payable	(30,850)	9,332
Accrued and other current liabilities	(17,045)	(10,088)
Other non-current assets	(2,118)	138
Other non-current liabilities	(4,741)	(6,865)
Net cash provided by operating activities	687,310	549,773
Cash flows from investing activities:
Capital expenditures	(303,689)	(380,072)
Equity investment in VTTI B.V.	(1,387,844)	0
Acquisitions, net of working capital settlement	0	(25,941)
Proceeds from asset disposals	429	2,235
Escrow deposits	0	19,850
Recoveries on property damages	4,621	5,700
Distributions in excess of earnings from equity investments	16,951	0
Net cash used in investing activities	(1,669,532)	(378,228)
Cash flows from financing activities:
Net proceeds from issuance of LP Units	345,955	108,422
Net proceeds from exercise of Unit options	481	300
Payment of tax withholding on issuance of LTIP awards	(8,487)	(5,123)
Repayment of long-term debt	(125,000)	0
Debt issuance costs	(29)	(1,240)
Borrowings under BPL Credit Facility	1,544,972	978,700
Repayments under BPL Credit Facility	(1,047,372)	(1,136,800)
Net borrowings under BMSC Credit Facility	185,410	106,852
Borrowings under Term Loan	0	250,000
Contributions from noncontrolling interests	7,700	3,760
Distributions to noncontrolling interests	(24,657)	(11,531)
Distributions to unitholders	(529,169)	(469,764)
Net cash provided by (used in) financing activities	349,804	(176,424)
Net decrease in cash and cash equivalents	(632,418)	(4,879)
Cash and cash equivalents — Beginning of period	640,340	4,881
Cash and cash equivalents — End of period	$ 7,922	$ 2

CONDENSED CONSOLIDATED STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL - USD ($) $ in Thousands	Total	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests	Limited Partners
Beginning balance at Dec. 31, 2015	$ 4,016,741	$ (97,841)	$ 281,352	$ 3,833,230
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	439,746		11,803	427,943
Distributions paid to unitholders	(469,764)		2,292	(472,056)
Net proceeds from issuance of LP Units	108,422			108,422
Amortization of unit-based compensation awards	22,977			22,977
Net proceeds from exercise of Unit options	300			300
Payment of tax withholding on issuance of LTIP awards	(5,123)			(5,123)
Distributions paid to noncontrolling interests	(11,531)		(11,531)
Contributions from noncontrolling interests	3,760		3,760
Other comprehensive income	9,654	9,654
Accrual of distribution equivalent rights	(2,248)			(2,248)
Other			44	(44)
Ending balance at Sep. 30, 2016	4,112,934	(88,187)	287,720	3,913,401
Beginning balance at Dec. 31, 2016	4,698,423	(25,593)	286,700	4,437,316
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	362,912		10,427	352,485
Distributions paid to unitholders	(529,169)		2,182	(531,351)
Net proceeds from issuance of LP Units	345,955			345,955
Amortization of unit-based compensation awards	25,935			25,935
Net proceeds from exercise of Unit options	481			481
Payment of tax withholding on issuance of LTIP awards	(8,487)			(8,487)
Distributions paid to noncontrolling interests	(24,657)		(24,657)
Contributions from noncontrolling interests	7,700		7,700
Other comprehensive income	36,863	36,863
Accrual of distribution equivalent rights	(2,931)			(2,931)
Other			141	(141)
Ending balance at Sep. 30, 2017	$ 4,913,025	$ 11,270	$ 282,493	$ 4,619,262

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	9 Months Ended
	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND BASIS OF PRESENTATION	1. ORGANIZATION AND BASIS OF PRESENTATION Organization Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership (“MLP”), and its limited partnership units representing limited partner interests (“LP Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner. As used in these Notes to Unaudited Condensed Consolidated Financial Statements, “ we ,” “ us ,” “ our ” and “ Buckeye ” mean Buckeye Partners, L.P. and, where the context requires, includes our subsidiaries. We own and operate, or own a significant interest in, a diversified global network of integrated assets providing midstream logistic solutions, primarily consisting of the transportation, storage, processing and marketing of liquid petroleum products. We are one of the largest independent liquid petroleum products pipeline operators in the United States in terms of volumes delivered and miles of pipeline. We also use our service expertise to operate and/or maintain third-party pipelines and perform certain engineering and construction services for our customers. Our global terminal network, including through our interest in VTTI B.V. (“VTTI”), comprises active product terminals across our portfolio of pipelines, inland terminals and marine terminals located primarily in key petroleum logistics hubs in the East Coast, Midwest and Gulf Coast regions of the United States as well as in the Caribbean, Northwest Europe, the Middle East and Southeast Asia. Our global network of marine terminals enables us to facilitate global flows of crude oil and refined petroleum products, offering our customers connectivity between supply areas and market centers through some of the world’s most important bulk liquid storage and blending hubs. Our flagship marine terminal in The Bahamas, Buckeye Bahamas Hub Limited (“BBH”), is one of the largest marine crude oil and refined petroleum products storage facilities in the world and provides an array of logistics and blending services for the global flow of petroleum products. Our Gulf Coast regional hub, Buckeye Texas Partners LLC (“Buckeye Texas”), offers world-class marine terminalling, storage and processing capabilities. Through our 50% equity interest in VTTI, our global terminal network offers premier storage and marine terminalling services for petroleum product logistics in key international energy hubs. We are also a wholesale distributor of refined petroleum products in certain areas served by our pipelines and terminals. Basis of Presentation and Principles of Consolidation The unaudited condensed consolidated financial statements and the accompanying notes are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules of the U.S. Securities and Exchange Commission. Accordingly, our financial statements reflect all normal and recurring adjustments that are, in the opinion of management, necessary for a fair presentation of our results of operations for the interim periods. The unaudited condensed consolidated financial statements include the accounts of our subsidiaries controlled by us and variable interest entities of which we are the primary beneficiary. Intercompany transactions are eliminated in consolidation. We believe that the disclosures in these unaudited condensed consolidated financial statements are adequate to make the information presented not misleading. These interim financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2016 . Recent Accounting Developments Derivatives and Hedging . In August 2017, the Financial Accounting Standards Board (“FASB”) issued guidance which amends and simplifies existing guidance in order to improve the financial reporting of hedging relationships to better align risk management activities in financial statements and make targeted improvements to simplify the application of current guidance related to the assessment of hedge effectiveness. The amendments are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early application permitted. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements. Modifications to Share-Based Payment Awards . In May 2017, the FASB issued guidance to clarify when changes in the terms or conditions of share-based payment awards must be accounted for as modifications under Topic 718. The guidance requires that entities apply modification accounting unless the award’s fair value, vesting conditions and classification as an equity or liability instrument are the same immediately before and after the change. The amendments are effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted. The amendments should be applied prospectively to awards modified on or after the adoption date. We expect to adopt this guidance on January 1, 2018, and it will be applied to modifications of our unit-based awards prospectively, if any. Retirement Benefits . In March 2017, the FASB issued guidance to amend the presentation of net periodic pension cost and net periodic postretirement benefit cost. The guidance requires that the service cost component of net periodic pension and postretirement benefit cost be presented in the same income statement line item as other employee compensation costs, while the other components are required to be presented separately within non-operating income. The guidance also allows only the service cost component to be eligible for capitalization when applicable. The amendments are effective for interim and annual periods beginning after December 15, 2017. The amendments should be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit in assets. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements. Revenue from Contracts with Customers . In May 2014, the FASB issued Accounting Standards Update No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which amended existing accounting standards for revenue recognition, including industry-specific requirements, and provides entities with a single revenue recognition model for recognizing revenue from contracts with customers. The core principle of ASU 2014-09 is that an entity should recognize revenue from contracts with customers when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Furthermore, additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. The two permitted transition methods under ASU 2014-09 are the full retrospective method, which would be applied to each prior reporting period presented and the cumulative effect of applying the standard would be recognized at the earliest period shown, or the modified retrospective method, in which the cumulative effect of applying the standard would be recognized at the date of initial application. In July 2015, the FASB deferred the effective date of ASU 2014-09 and is effective for annual and interim periods beginning after December 15, 2017, with early adoption permitted for annual and interim periods beginning after December 15, 2016. In 2016, the FASB issued accounting standards updates that amended several aspects of ASU 2014-09. We continue to evaluate the provisions of the standard through our implementation work team, consisting of representatives from all of our business segments, and to assess and implement changes to business processes, systems and controls, as necessary. In addition, we have implemented training on the new standard’s revenue recognition model and are continuing our contract review and documentation. We will adopt this guidance on January 1, 2018, and we are currently evaluating the impact that it will have on our consolidated financial statements, including our disclosures, under the elected modified retrospective transition method. To date, we have not identified any customer arrangements which would require a significant change to the timing of our revenue recognition, although our analysis is not yet complete. Equity-Based Compensation . In March 2016, the FASB issued guidance to simplify several aspects of the accounting for employee equity-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows and classification of awards as liabilities or equity. The guidance was effective for annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods, with early adoption permitted. Amendments related to the timing of when excess tax benefits are recognized, statutory withholding requirements and forfeitures were to be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows were to be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement were to be applied prospectively. Amendments related to the presentation of excess tax benefits on the statement of cash flows were to be applied using either a prospective transition method or a retrospective transition method. We adopted this guidance as of January 1, 2017 and did not recognize a retrospective transition adjustment. The adoption of this guidance did not have a material impact on our consolidated financial statements or on our disclosures.

ACQUISITIONS

ACQUISITIONS	9 Months Ended
	Sep. 30, 2017
Business Combinations [Abstract]
ACQUISITIONS	2. ACQUISITIONS Business Combination Indianola terminalling facility acquisition In August 2016, we acquired a liquid petroleum products terminalling facility in Indianola, Pennsylvania from Kinder Morgan Transmix Company, LLC for $26.0 million . The operations of these assets are reported in our Domestic Pipelines & Terminals segment. The acquisition cost has been allocated on a preliminary basis to assets acquired based on estimated fair values at the acquisition date, with amounts exceeding the fair value recorded as goodwill, which represent expected synergies from combining the acquired assets with our existing operations. Fair values have been developed using recognized business valuation techniques. The purchase price has been allocated to tangible and intangible assets acquired as follows (in thousands): Inventories $ 1,554 Property, plant and equipment 16,713 Goodwill 7,758 Allocated purchase price $ 26,025 We finalized the purchase price allocation during the third quarter of 2017 without significant adjustment. Unaudited Pro forma Financial Results for the Indianola terminalling facility acquisition Our consolidated statements of operations do not include earnings from the terminalling facility prior to August 4, 2016, the closing date of the acquisition. The preparation of unaudited pro forma financial information for the terminalling facility is impracticable due to the fact that meaningful historical revenue information is not available. The revenues and earnings impact of this acquisition was not significant to our financial results for the three and nine months ended September 30, 2017 . Equity Investment Transaction VTTI Acquisition In January 2017, we acquired an indirect 50% equity interest in VTTI for cash consideration of $1.15 billion (the “VTTI Acquisition”). We own VTTI jointly with Vitol S.A. (“Vitol”). VTTI is one of the largest independent global marine terminal businesses which, through its subsidiaries and partnership interests, owns and operates approximately 58 million barrels of petroleum products storage across 15 terminals located on five continents. These marine terminals are predominately located in key global energy hubs, including Northwest Europe, the United Arab Emirates and Singapore, and offer world-class storage and marine terminalling services for refined petroleum products, liquid petroleum gas and crude oil. We and VIP Terminals Finance B.V., a subsidiary of Vitol, have equal board representation and voting rights in the VTTI joint venture. We account for this investment using the equity method of accounting. Under this method, an investment is recorded at acquisition cost plus our equity in undistributed earnings or losses since acquisition, reduced by distributions received and amortization of excess net investment. The earnings from our equity investment in VTTI are reported in our Global Marine Terminals segment. In addition, we include our proportionate share of our equity method investments’ unrealized gains and losses in other comprehensive income in our unaudited condensed consolidated financial statements. The estimated fair values used to calculate the excess net investment in VTTI were primarily developed using an income approach, with inputs classified as Level 3 within the fair value hierarchy. The excess net investment was $583.3 million at the acquisition date and was comprised of the following components: (i) $233.0 million related to the excess of the fair values of identifiable property, plant and equipment and intangible assets over their carrying values, which is being amortized on a straight-line basis over the estimated useful lives of these underlying assets of approximately 28 years ; and (ii) $350.3 million of implied goodwill, which is not subject to amortization. The amortization of the excess net investment is included in earnings from equity investments on our unaudited condensed consolidated statements of operations. In September 2017, VTTI acquired all of the outstanding publicly held common units of VTTI Energy Partners LP, formerly a publicly traded master limited partnership (“VTTI MLP”), for an aggregate cash consideration of $473.6 million (the “VTTI Merger”). In connection with the VTTI Merger, VTTI MLP merged with and into a direct wholly owned subsidiary of VTTI. We funded our 50% share of the aggregate cash consideration, in the amount of $236.8 million , through a capital contribution to VTTI, using borrowings under our Credit Facility.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	9 Months Ended
	Sep. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	3. COMMITMENTS AND CONTINGENCIES Claims and Legal Proceedings In the ordinary course of business, we are involved in various claims and legal proceedings, some of which are covered by insurance. We are generally unable to predict the timing or outcome of these claims and proceedings. Based upon our evaluation of existing claims and proceedings and the probability of losses relating to such contingencies, we have accrued certain amounts relating to such claims and proceedings, none of which are considered material. Environmental Contingencies At September 30, 2017 and December 31, 2016 , we had $41.9 million and $44.3 million , respectively, of environmental remediation liabilities unrelated to claims and legal proceedings. Costs ultimately incurred may be in excess of our estimates, which may have a material impact on our financial condition, results of operations or cash flows. At September 30, 2017 and December 31, 2016 , we had $5.7 million and $7.2 million , respectively, of receivables related to these environmental remediation liabilities covered by insurance or third-party claims.

INVENTORIES

INVENTORIES	9 Months Ended
	Sep. 30, 2017
Inventory Disclosure [Abstract]
INVENTORIES	4. INVENTORIES Our inventory amounts were as follows at the dates indicated (in thousands): September 30, December 31, Liquid petroleum products (1) $ 210,747 $ 337,424 Materials and supplies 22,666 19,379 Total inventories $ 233,413 $ 356,803 (1) Ending inventory was 122.3 million and 198.2 million gallons of liquid petroleum products as of September 30, 2017 and December 31, 2016 , respectively. At September 30, 2017 and December 31, 2016 , approximately 86% and 88% of our liquid petroleum products inventory volumes were designated in a fair value hedge relationship, respectively. Because we generally designate inventory as a hedged item upon purchase, hedged inventory is valued at current market prices with the change in value of the inventory reflected in our unaudited condensed consolidated statements of operations. Our inventory volumes that are not designated as the hedged item in a fair value hedge relationship are economically hedged to reduce our commodity price exposure. Inventory not accounted for as a fair value hedge is accounted for at the lower of weighted average cost method or net realizable value.

PREPAID AND OTHER CURRENT ASSET

PREPAID AND OTHER CURRENT ASSETS	9 Months Ended
	Sep. 30, 2017
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
PREPAID AND OTHER CURRENT ASSETS	5. PREPAID AND OTHER CURRENT ASSETS Prepaid and other current assets consist of the following at the dates indicated (in thousands): September 30, December 31, Prepaid insurance $ 13,446 $ 7,609 Margin deposits 8,184 43,912 Unbilled revenue 9,003 1,615 Prepaid taxes 5,212 7,357 Vendor prepayments 767 1,863 Other 3,941 4,180 Total prepaid and other current assets $ 40,553 $ 66,536

EQUITY INVESTMENTS

EQUITY INVESTMENTS	9 Months Ended
	Sep. 30, 2017
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS	6. EQUITY INVESTMENTS The following table presents earnings from equity investments for the periods indicated (in thousands): Three Months Ended Nine Months Ended Segment 2017 2016 2017 2016 VTTI B.V. (1) Global Marine Terminals $ 6,396 $ — $ 15,111 $ — West Shore Pipe Line Company Domestic Pipelines & Terminals 1,772 1,784 4,913 5,680 Muskegon Pipeline LLC Domestic Pipelines & Terminals 501 544 1,303 1,340 Transport4, LLC Domestic Pipelines & Terminals 206 204 650 577 South Portland Terminal LLC Domestic Pipelines & Terminals 357 369 733 862 Total earnings from equity investments $ 9,232 $ 2,901 $ 22,710 $ 8,459 (1) We acquired an indirect 50% equity interest in VTTI in January 2017. For additional information, see Note 2 . Summarized combined income statement data for our equity method investments are as follows for the periods indicated (amounts represent 100% of investee income statement data in thousands): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Revenue $ 143,946 $ 22,831 $ 403,985 $ 65,877 Operating income 52,766 12,805 138,195 35,411 Net income 30,874 8,663 84,807 23,986 Net income attributable to investee 23,565 8,663 63,347 23,986

LONG-TERM DEBT

LONG-TERM DEBT	9 Months Ended
	Sep. 30, 2017
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT Extinguishment of Debt In July 2017, we repaid in full the $125.0 million principal amount and $3.2 million of accrued interest outstanding under our 5.125% notes, using funds available under our $1.5 billion revolving credit facility. Current Maturities Expected to be Refinanced We have classified $300.0 million of 6.050% notes due on January 15, 2018 as long-term debt in the unaudited condensed consolidated balance sheet at September 30, 2017 because we have the intent and the ability to refinance these obligations on a long-term basis under our Credit Facility. At September 30, 2017 , we had $814.6 million of additional borrowing capacity under our Credit Facility.

DERIVATIVE INSTRUMENTS AND HEDG

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	9 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES We are exposed to financial market risks, including changes in interest rates and commodity prices, in the course of our normal business operations. We use derivative instruments to manage such risks. Interest Rate Derivatives From time to time, we utilize forward-starting interest rate swaps to hedge the variability of the forecasted interest payments on anticipated debt issuances that may result from changes in the benchmark interest rate until the expected debt is issued. When entering into interest rate swap transactions, we become exposed to both credit risk and market risk. We are subject to credit risk when the change in fair value of the swap instrument is positive and the counterparty may fail to perform under the terms of the contract. We are subject to market risk with respect to changes in the underlying benchmark interest rate that impacts the fair value of the swaps. We manage our credit risk by entering into swap transactions only with major financial institutions with investment-grade credit ratings. We manage our market risk by aligning the swap instrument with the existing underlying debt obligation or a specified expected debt issuance, generally associated with the maturity of an existing debt obligation. We designate the swap agreements as cash flow hedges at inception and expect the changes in values to be highly correlated with the changes in value of the underlying borrowings. During 2016, we entered into seven forward-starting interest rate swaps with a total aggregate notional amount of $350.0 million , which we entered into in anticipation of the issuance of debt on or before January 15, 2018, and eleven forward-starting interest rate swaps with a total aggregate notional amount of $500.0 million , which we entered into in anticipation of the issuance of debt on or before November 15, 2018. We expect to issue new fixed-rate debt on or before January 15, 2018 to repay the $300.0 million of 6.050% notes that are due on January 15, 2018, and on or before November 15, 2018 to repay the $400.0 million of 2.650% notes that are due on November 15, 2018, as well as to fund capital expenditures and other general partnership purposes, although no assurances can be given that the issuance of fixed-rate debt will be possible on acceptable terms. During the three and nine months ended September 30, 2017 , unrealized losses of $2.2 million and $12.7 million , respectively, were recorded in accumulated other comprehensive income (“AOCI”) to reflect the change in the fair values of the forward-starting interest rate swaps. Commodity Derivatives Our Merchant Services segment primarily uses exchange-traded refined petroleum product futures contracts to manage the risk of market price volatility on its refined petroleum product inventories and its physical derivative contracts, which we designated as fair value hedges, with changes in fair value of both the futures contracts and physical inventory reflected in earnings. Our Merchant Services segment also uses exchange-traded refined petroleum contracts to hedge expected future transactions related to certain gasoline inventory that we manage on behalf of a third party, which are designated as cash flow hedges, with the effective portion of the hedge reported in other comprehensive income (“OCI”) and reclassified into earnings when the expected future transaction affects earnings. Any gains or losses incurred on the derivative instruments that are not effective in offsetting changes in fair value or cash flows of the hedged item are recognized immediately in earnings. Additionally, our Merchant Services segment enters into exchange-traded refined petroleum product futures contracts on behalf of our Domestic Pipelines & Terminals segment to manage the risk of market price volatility on the gasoline-to-butane pricing spreads associated with our butane blending activities managed by a third party. These futures contracts are not designated in a hedge relationship for accounting purposes. Physical forward contracts and futures contracts that have not been designated in a hedge relationship are marked-to-market. The following table summarizes our commodity derivative instruments outstanding at September 30, 2017 (amounts in thousands of gallons): Volume (1) Derivative Purpose Current Long-Term Derivatives NOT designated as hedging instruments: Physical fixed-price derivative contracts 7,115 1,110 Physical index derivative contracts 35,385 — Futures contracts for refined petroleum products 241 6,090 Hedge Type Derivatives designated as hedging instruments: Physical fixed-price derivative contracts 1,050 — Cash Flow Hedge Cash flow hedge futures contracts 13,104 8,400 Cash Flow Hedge Futures contracts for refined petroleum products 100,632 4,494 Fair Value Hedge (1) Volume represents absolute value of net notional volume position. All volumes represent net short positions, except for the physical fixed-price derivative contracts designated as a cash flow hedge. Our futures contracts designated as fair value hedges relate to our inventory portfolio and extend to the fourth quarter of 2018. Our futures contracts and physical fixed-priced derivative contracts designated as cash flow hedges relate to forecasted purchases and sales of refined petroleum products and extend to the third quarter of 2018 . Effective January 2017, the Chicago Mercantile Exchange (“CME”) amended its rulebook, resulting in the characterization of variation margin transfers as settlement payments, as opposed to adjustments to collateral. These amendments impacted the accounting treatment of our exchange-traded derivatives contracts, primarily comprised of our futures contracts, for which the CME serves as the central clearing party, and exchange-settled derivatives traded on the over-the-counter (“OTC”) market. As a result, commencing with the first quarter of 2017, we began reducing the corresponding derivative asset and liability balances for our exchange-settled derivative contracts to reflect the settlement of those positions via the variation margin. The variation margin is now considered partial settlement of the derivative contract and will result in realized gains or losses which, prior to January 1, 2017, were classified as unrealized gains or losses on derivatives. In addition, we maintain an initial margin deposit with the broker in an amount sufficient to cover the fair value of our open futures positions. This margin deposit is considered collateral and is included within prepaid and other current assets in our condensed consolidated balance sheets and is not offset against the fair values of our derivative instruments. The following table sets forth the fair value of each classification of derivative instruments and the locations of the derivative instruments on our unaudited condensed consolidated balance sheets at the dates indicated (in thousands): September 30, 2017 Derivatives NOT Designated as Hedging Instruments Derivatives Designated as Hedging Instruments Derivative Carrying Value Netting Balance Sheet Adjustment (1) Net Total Physical fixed-price derivative contracts $ 816 $ — $ 816 $ (95 ) $ 721 Physical index derivative contracts 226 — 226 (2 ) 224 Interest rates derivatives — 49,939 49,939 — 49,939 Total current derivative assets 1,042 49,939 50,981 (97 ) 50,884 Physical fixed-price derivative contracts 2 — 2 — 2 Total non-current derivative assets 2 — 2 — 2 Physical fixed-price derivative contracts (3,558 ) (104 ) (3,662 ) 95 (3,567 ) Physical index derivative contracts (3 ) — (3 ) 2 (1 ) Total current derivative liabilities (3,561 ) (104 ) (3,665 ) 97 (3,568 ) Physical fixed-price derivative contracts (84 ) — (84 ) — (84 ) Total non-current derivative liabilities (84 ) — (84 ) — (84 ) Net derivative (liabilities) assets $ (2,601 ) $ 49,835 $ 47,234 $ — $ 47,234 (1) Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists. Futures contracts are subject to settlement through margin requirements and are additionally presented on a net basis. December 31, 2016 Derivatives NOT Designated as Hedging Instruments Derivatives Designated as Hedging Instruments Derivative Carrying Value Netting Balance Sheet Adjustment (1) Net Total Physical fixed-price derivative contracts $ 1,499 $ — $ 1,499 $ (306 ) $ 1,193 Physical index derivative contracts 334 — 334 (1 ) 333 Futures contracts for refined products 51,431 21 51,452 (51,452 ) — Total current derivative assets 53,264 21 53,285 (51,759 ) 1,526 Physical fixed-price derivative contracts 164 — 164 (5 ) 159 Futures contracts for refined products 226 — 226 (226 ) — Interest rates derivatives — 62,609 62,609 — 62,609 Total non-current derivative assets 390 62,609 62,999 (231 ) 62,768 Physical fixed-price derivative contracts (4,517 ) — (4,517 ) 306 (4,211 ) Physical index derivative contracts (1 ) — (1 ) 1 — Futures contracts for refined products (57,828 ) (15,685 ) (73,513 ) 51,452 (22,061 ) Total current derivative liabilities (62,346 ) (15,685 ) (78,031 ) 51,759 (26,272 ) Physical fixed-price derivative contracts (61 ) — (61 ) 5 (56 ) Futures contracts for refined products (4,384 ) — (4,384 ) 226 (4,158 ) Total non-current derivative liabilities (4,445 ) — (4,445 ) 231 (4,214 ) Net derivative (liabilities) assets $ (13,137 ) $ 46,945 $ 33,808 $ — $ 33,808 (1) Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists. Futures contracts are subject to settlement through margin requirements and are additionally presented on a net basis. At September 30, 2017 , open refined petroleum product derivative contracts (represented by the physical fixed-price contracts, physical index contracts, and futures contracts for refined products contracts noted above) varied in duration in the overall portfolio, but did not extend beyond December 2018 . In addition, at September 30, 2017 , we had refined petroleum product inventories that we intend to use to satisfy a portion of the physical derivative contracts. The gains and losses on our derivative instruments recognized in income were as follows for the periods indicated (in thousands): Three Months Ended Nine Months Ended Location 2017 2016 2017 2016 Derivatives NOT designated as hedging instruments: Physical fixed-price derivative contracts Product sales $ (7,209 ) $ 301 $ (257 ) $ (7,263 ) Physical index derivative contracts Product sales 57 142 58 130 Physical fixed-price derivative contracts Cost of product sales 1,462 479 1,380 7,965 Physical index derivative contracts Cost of product sales 115 30 453 193 Futures contracts for refined products Cost of product sales 15,861 (307 ) 15,061 4,326 Derivatives designated as fair value hedging instruments: Futures contracts for refined products Cost of product sales $ (51,093 ) $ (635 ) $ 1,758 $ (27,590 ) Physical inventory - hedged items Cost of product sales 48,236 3,620 7,536 43,627 Ineffectiveness excluding the time value component on fair value hedging instruments: Fair value hedge ineffectiveness (excluding time value) Cost of product sales $ (3,299 ) $ (4,262 ) $ (5,929 ) $ (4,275 ) Time value excluded from hedge assessment Cost of product sales 442 7,247 15,223 20,312 Net (loss) gain in income $ (2,857 ) $ 2,985 $ 9,294 $ 16,037 The change in value recognized in OCI and the gains and losses reclassified from AOCI to income attributable to our derivative instruments designated as cash flow hedges were as follows for the periods indicated (in thousands): (Loss) Gain Recognized in OCI on Derivatives for the Three Months Ended Nine Months Ended 2017 2016 2017 2016 Derivatives designated as cash flow hedging instruments: Interest rate contracts $ (2,207 ) $ 1,052 $ (12,670 ) $ 1,052 Commodity derivatives (3,557 ) — 675 — Total $ (5,764 ) $ 1,052 $ (11,995 ) $ 1,052 (Loss) Gain Reclassified from AOCI to Income (Effective Portion) for the Three Months Ended Nine Months Ended Location 2017 2016 2017 2016 Derivatives designated as cash flow hedging instruments: Interest rate contracts Interest and debt expense $ (3,038 ) $ (3,037 ) $ (9,113 ) $ (9,112 ) Commodity derivatives Product Sales — — — 1,266 Total $ (3,038 ) $ (3,037 ) $ (9,113 ) $ (7,846 ) Over the next twelve months, we expect to reclassify $9.8 million of net losses attributable to interest rate derivatives from AOCI to earnings as an increase to interest and debt expense. These net losses consist of $11.5 million of amortization of hedge losses on our settled forward-starting interest rate swaps, partially offset by $1.7 million of amortization of forecasted hedge gains on our forward-starting interest swaps that we expect to settle in late 2017. Additionally, $0.7 million of unrealized gains for refined petroleum products derivatives designated as cash flow hedges at September 30, 2017 are estimated to be realized and reclassified from AOCI to product sales over the next twelve months. The ineffective portion of the change in fair value of cash flow hedges was not material for the three and nine months ended September 30, 2017 .

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	9. FAIR VALUE MEASUREMENTS We categorize our financial assets and liabilities using the three-tier fair value hierarchy as follows: Recurring The following table sets forth financial assets and liabilities measured at fair value on a recurring basis, as of the measurement dates indicated, and the basis for that measurement, by level within the fair value hierarchy (in thousands): September 30, 2017 December 31, 2016 Level 1 Level 2 Level 1 Level 2 Financial assets: Physical fixed-price derivative contracts $ — $ 818 $ — $ 1,352 Physical index derivative contracts — 226 — 333 Interest rate derivatives — 49,939 — 62,609 Financial liabilities: Physical fixed-price derivative contracts — (3,746 ) — (4,267 ) Physical index derivative contracts — (3 ) — — Futures contracts for refined products — — (26,219 ) — Fair value $ — $ 47,234 $ (26,219 ) $ 60,027 The values of the Level 1 derivative assets and liabilities were based on quoted market prices obtained from the New York Mercantile Exchange. The values for exchange-settled commodity derivatives at September 30, 2017 are presented after the application of the CME rulebook amendment, which deems that these instruments are settled daily via variation margin payments. As a result of this rulebook amendment, CME-settled derivatives, primarily comprised of our futures contracts for refined petroleum products, are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. The values of the Level 2 interest rate derivatives were determined using fair value estimates obtained from our counterparties, which are verified using other available market data, including cash flow models which incorporate market inputs, including the implied forward LIBOR yield curve for the same period as the future interest rate swap settlements. Credit value adjustments (“CVAs”), which are used to reflect the potential nonperformance risk of our counterparties, are considered in the fair value assessment of interest rate derivatives. We determined that the impact of CVAs is not significant to the overall valuation of interest rate derivatives. The values of the Level 2 commodity derivative contracts were calculated using market approaches based on observable market data inputs, including published commodity pricing data, which is verified against other available market data, and market interest rate and volatility data. Level 2 physical fixed-price derivative assets are net of CVAs determined using an expected cash flow model, which incorporates assumptions about the credit risk of the derivative contracts based on the historical and expected payment history of each customer, the amount of product contracted for under the agreement and the customer’s historical and expected purchase performance under each contract. The Merchant Services segment determined CVAs are appropriate because few of the Merchant Services segment’s customers entering into these derivative contracts are large organizations with nationally recognized credit ratings. The CVAs were nominal as of September 30, 2017 and December 31, 2016 . As of September 30, 2017 and December 31, 2016 , the Merchant Services segment did not hold any net liability derivative position containing credit contingent features. Financial instruments included in current assets and current liabilities are reported in the unaudited condensed consolidated balance sheets at amounts which approximate fair value due to the relatively short period to maturity of these financial instruments. The fair values of our fixed-rate debt were estimated by observing market trading prices and by comparing the historic market prices of our publicly issued debt with the market prices of the publicly issued debt of other MLPs with similar credit ratings and terms. The fair values of our variable-rate debt are their carrying amounts, as the carrying amount reasonably approximates fair value due to the variability of the interest rates. The carrying value and fair value of our debt, using Level 2 input values, were as follows at the dates indicated (in thousands): September 30, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value Fixed-rate debt $ 3,846,426 $ 4,016,825 $ 3,967,695 $ 4,083,488 Variable-rate debt 932,619 933,010 250,000 250,000 Total debt $ 4,779,045 $ 4,949,835 $ 4,217,695 $ 4,333,488 We recognize transfers between levels within the fair value hierarchy as of the beginning of the reporting period. We did not have any transfers between Level 1 and Level 2 during the nine months ended September 30, 2017 and 2016 , respectively. Non-Recurring Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment. For the three and nine months ended September 30, 2017 and 2016 , there were no significant fair value adjustments related to such assets or liabilities reflected in our unaudited condensed consolidated financial statements.

UNIT-BASED COMPENSATION PLANS

UNIT-BASED COMPENSATION PLANS	9 Months Ended
	Sep. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
UNIT-BASED COMPENSATION PLANS	10. UNIT-BASED COMPENSATION PLANS We award unit-based compensation to employees and directors primarily under the Buckeye Partners, L.P. 2013 Long-Term Incentive Plan (as amended and restated effective June 6, 2017, the “LTIP”). We formerly awarded options to acquire LP Units to employees pursuant to the Buckeye Partners, L.P. Unit Option and Distribution Equivalent Plan (the “Option Plan”). These compensation plans are further discussed below. We recognized compensation expense related to the LTIP and the Option Plan, of $8.2 million and $8.9 million for the three months ended September 30, 2017 and 2016 , respectively. For the nine months ended September 30, 2017 and 2016 , we recognized compensation expense of $25.9 million and $23.0 million , respectively. LTIP As of September 30, 2017 , there were 2,646,326 LP Units available for issuance under the LTIP. Deferral Plan under the LTIP We also maintain the Buckeye Partners, L.P. Unit Deferral and Incentive Plan, as amended and restated effective February 4, 2015 (the “Deferral Plan”), pursuant to which we issue phantom and matching units under the LTIP to certain employees in lieu of a portion of the cash payments such employees would be entitled to receive under the Buckeye Partners, L.P. Annual Incentive Compensation Plan, as amended and restated, effective January 1, 2012. At December 31, 2016 and 2015 , actual compensation awards deferred under the Deferral Plan were $4.4 million and $3.1 million , for which 145,138 and 139,526 phantom units (including matching units) were granted during the nine months ended September 30, 2017 and the year ended December 31, 2016 , respectively. These grants are included as granted in the LTIP activity table below. Awards under the LTIP During the nine months ended September 30, 2017 , the Compensation Committee of the board of directors of Buckeye GP granted 316,490 phantom units to employees (including the 145,138 phantom units granted pursuant to the Deferral Plan, as discussed above), 18,000 phantom units to independent directors of Buckeye GP and 212,062 performance units to employees. The following table sets forth the LTIP activity for the periods indicated (in thousands, except per unit amounts): Number of LP Units Weighted Average Grant Date Fair Value per LP Unit (1) Unvested at January 1, 2017 1,296 $ 63.54 Granted (2) 547 69.93 Performance adjustment (3) 32 71.50 Vested (333 ) 70.30 Forfeited (32 ) 64.48 Unvested at September 30, 2017 1,510 $ 64.47 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per LP Unit for forfeited and vested awards is determined before an allowance for forfeitures. (2) Includes both phantom and performance awards. Performance awards are granted at a target amount but, depending on our performance during the vesting period with respect to certain pre-established goals, the number of LP Units issued upon vesting of such performance awards can be greater or less than the target amount. (3) Represents the LP Units issued in excess of target amounts for performance awards that vested during the nine months ended September 30, 2017 as a result of our above target performance with respect to applicable performance goals. At September 30, 2017 , $40.5 million of compensation expense related to the LTIP is expected to be recognized over a weighted average period of 1.8 years for the above awards. Unit Option Plan The following is a summary of the changes in the options outstanding (all of which are vested) under the Option Plan for the periods indicated (in thousands, except per unit amounts): Number of LP Units Weighted Average Strike Price per LP Unit Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (1) Outstanding at January 1, 2017 10 $ 50.36 0.1 $ 151 Exercised (10 ) — Outstanding at September 30, 2017 — — — $ — Exercisable at September 30, 2017 — $ — — $ — (1) Aggregate intrinsic value reflects fully vested LP Unit options at the date indicated. Intrinsic value is determined by calculating the difference between our closing LP Unit price on the last trading day in September 2017 and the exercise price, multiplied by the number of exercisable, in-the-money options. The total intrinsic value of options exercised during each of the nine months ended September 30, 2017 and 2016 was $0.2 million and $0.1 million , respectively.

PARTNERS' CAPITAL AND DISTRIBUT

PARTNERS' CAPITAL AND DISTRIBUTIONS	9 Months Ended
	Sep. 30, 2017
Equity [Abstract]
PARTNERS' CAPITAL AND DISTRIBUTIONS	11. PARTNERS’ CAPITAL AND DISTRIBUTIONS Our LP Units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights and privileges available to them under our partnership agreement. The partnership agreement provides that, without prior approval of our limited partners holding an aggregate of at least two-thirds of the outstanding LP Units, we cannot issue any LP Units of a class or series having preferences or other special or senior rights over the LP Units. At-the-Market Offering Program In March 2016, we entered into an equity distribution agreement (the “Equity Distribution Agreement”) with J.P. Morgan Securities LLC, BB&T Capital Markets, a division of BB&T Securities, LLC, BNP Paribas Securities Corp., Deutsche Bank Securities Inc., Jefferies LLC, Morgan Stanley & Co. LLC, RBC Capital Markets, LLC, and SMBC Nikko Securities America, Inc. (collectively, the “ATM Underwriters”). Under the terms of the Equity Distribution Agreement, we may offer and sell up to $500.0 million in aggregate gross sales proceeds of LP Units from time to time through the ATM Underwriters, acting as agents of Buckeye or as principals, subject in each case to the terms and conditions set forth in the Equity Distribution Agreement. Sales of LP Units, if any, may be made by means of ordinary brokers’ transactions on the NYSE or otherwise at market prices prevailing at the time of sale, at prices related to prevailing market prices or at negotiated prices or as otherwise agreed with any of such firms. During the nine months ended September 30, 2017 , we sold approximately 6.2 million LP Units under the Equity Distribution Agreement, including a block sale of approximately 3.8 million LP Units on September 21, 2017, and received $346.0 million in net proceeds after deducting commissions and other related expenses, including $1.9 million of compensation fees paid in aggregate to the ATM Underwriters. We used the net proceeds from the block sale to reduce the indebtedness outstanding under our Credit Facility and for general partnership purposes. Summary of Changes in Outstanding LP Units The following is a summary of changes in Buckeye ’ s outstanding LP Units for the periods indicated (in thousands): Limited Partners LP Units outstanding at January 1, 2017 140,264 LP Units issued pursuant to the Option Plan (1) 10 LP Units issued pursuant to the LTIP (1) 209 Issuance of LP Units through the Equity Distribution Agreement 6,159 LP Units outstanding at September 30, 2017 146,642 (1) The number of LP Units issued represents issuance net of tax withholding. Cash Distributions We generally make quarterly cash distributions to unitholders of substantially all of our available cash, generally defined in our partnership agreement as consolidated cash receipts less consolidated cash expenditures and such retentions for working capital and maintenance capital, anticipated cash expenditures and contingencies as our general partner deems appropriate. Actual cash distributions on our LP Units totaled $531.4 million ( $3.75 per LP Unit) and $472.1 million ( $3.60 per LP Unit) during the nine months ended September 30, 2017 and 2016 , respectively. On November 3, 2017 , we announced a quarterly distribution of $1.2625 per LP Unit that will be paid on November 20, 2017 to unitholders of record on November 13, 2017 . Based on the LP Units and distribution equivalent rights with respect to certain unit-based compensation awards outstanding as of September 30, 2017 , estimated cash to be distributed to unitholders on November 20, 2017 is $186.2 million .

EARNINGS PER UNIT

EARNINGS PER UNIT	9 Months Ended
	Sep. 30, 2017
Earnings Per Share [Abstract]
EARNINGS PER UNIT	12. EARNINGS PER UNIT The following table is a reconciliation of the weighted average units outstanding used in computing the basic and diluted earnings per unit for the periods indicated (in thousands, except per unit amounts): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Net income attributable to Buckeye Partners, L.P. $ 116,187 $ 156,374 $ 352,485 $ 427,943 Basic: Weighted average units outstanding - basic 142,088 131,113 141,104 130,439 Earnings per unit - basic $ 0.82 $ 1.19 $ 2.50 $ 3.28 Diluted: Weighted average units outstanding - basic 142,088 131,113 141,104 130,439 Dilutive effect of LP Unit options and LTIP awards granted 730 827 677 637 Weighted average units outstanding - diluted 142,818 131,940 141,781 131,076 Earnings per unit - diluted $ 0.81 $ 1.19 $ 2.49 $ 3.26

BUSINESS SEGMENTS

BUSINESS SEGMENTS	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
BUSINESS SEGMENTS	13. BUSINESS SEGMENTS We operate and report in three business segments: (i) Domestic Pipelines & Terminals; (ii) Global Marine Terminals; and (iii) Merchant Services. All inter-segment revenues, operating income and assets have been eliminated. Domestic Pipelines & Terminals The Domestic Pipelines & Terminals segment receives liquid petroleum products from refineries, connecting pipelines, vessels, and bulk and marine terminals, transports those products to other locations for a fee, and provides bulk liquid storage and terminal throughput services. The segment also has butane blending capabilities and provides crude oil services, including train loading/unloading, storage and throughput. This segment owns and operates pipeline systems and liquid petroleum products terminals in the continental United States, including three terminals owned by the Merchant Services segment but operated by the Domestic Pipelines & Terminals segment, and two underground propane storage caverns. Additionally, this segment provides turn-key operations and maintenance of third-party pipelines and performs pipeline construction management services typically for cost plus a fixed fee. Global Marine Terminals The Global Marine Terminals segment, including through its interest in VTTI, provides marine accessible bulk storage and blending services, rail and truck rack loading/unloading along with petroleum processing services in the New York Harbor on the East Coast and Corpus Christi, Texas in the Gulf Coast region of the United States, as well as The Bahamas, Puerto Rico and St Lucia in the Caribbean, Northwest Europe, the Middle East and Southeast Asia. The segment owns and operates, or owns a significant interest in, 22 liquid petroleum product terminals, located in these key domestic and international energy hubs, that enable us to facilitate global flows of crude and refined petroleum products, offer connectivity between supply areas and market centers, and provide premier storage, marine terminalling, blending, and processing services to a diverse customer base. Merchant Services The Merchant Services segment is a wholesale distributor of refined petroleum products in the United States and in the Caribbean. The segment’s products include gasoline, natural gas liquids, ethanol, biodiesel and petroleum distillates such as heating oil, diesel fuel, kerosene and fuel oil. The segment owns three terminals, which are operated by the Domestic Pipelines & Terminals segment. The segment’s customers consist principally of product wholesalers as well as major commercial users of these refined petroleum products. Financial Information by Segment The following table summarizes revenue by each segment for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Revenue: Domestic Pipelines & Terminals $ 254,277 $ 265,036 $ 761,438 $ 752,968 Global Marine Terminals 155,281 170,072 487,613 509,653 Merchant Services 526,844 344,041 1,498,438 1,103,186 Intersegment (13,783 ) (12,544 ) (45,396 ) (41,486 ) Total revenue $ 922,619 $ 766,605 $ 2,702,093 $ 2,324,321 For the three and nine months ended September 30, 2017 and 2016 , no customers contributed 10% or more of consolidated revenue. The following table summarizes revenue by major geographic area for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Revenue: United States $ 855,795 $ 683,850 $ 2,474,562 $ 2,072,893 International 66,824 82,755 227,531 251,428 Total revenue $ 922,619 $ 766,605 $ 2,702,093 $ 2,324,321 Adjusted EBITDA Adjusted EBITDA is a measure not defined by GAAP. We define Adjusted EBITDA as earnings before interest expense, income taxes, depreciation and amortization, further adjusted to exclude certain non-cash items, such as non-cash compensation expense; transaction, transition, and integration costs associated with acquisitions; certain gains and losses on foreign currency transactions and foreign currency derivative financial instruments, as applicable; and certain other operating expense or income items, reflected in net income, that we do not believe are indicative of our core operating performance results and business outlook, such as hurricane-related costs, gains and losses on property damage recoveries, and gains and losses on asset sales. The definition of Adjusted EBITDA is also applied to our proportionate share in the Adjusted EBITDA of significant equity method investments, such as that in VTTI, and is not applied to our less significant equity method investments. The calculation of our proportionate share of the reconciling items used to derive Adjusted EBITDA is based upon our 50% equity interest in VTTI, prior to adjustments related to noncontrolling interests in several of its subsidiaries and partnerships, which are immaterial. Adjusted EBITDA is a non-GAAP financial measure that is used by our senior management, including our Chief Executive Officer, to assess the operating performance of our business and optimize resource allocation. We use Adjusted EBITDA as a primary measure to: (i) evaluate our consolidated operating performance and the operating performance of our business segments; (ii) allocate resources and capital to business segments; (iii) evaluate the viability of proposed projects; and (iv) determine overall rates of return on alternative investment opportunities. We believe that investors benefit from having access to the same financial measures that we use and that these measures are useful to investors because they aid in comparing our operating performance with that of other companies with similar operations. The Adjusted EBITDA data presented by us may not be comparable to similarly titled measures at other companies because these items may be defined differently by other companies. The following tables present Adjusted EBITDA by segment and on a consolidated basis and a reconciliation of net income, which is the most comparable financial measure under GAAP, to Adjusted EBITDA for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Adjusted EBITDA: Domestic Pipelines & Terminals $ 138,880 $ 152,785 $ 413,710 $ 423,245 Global Marine Terminals 128,696 110,705 391,084 325,710 Merchant Services 9,742 8,159 19,224 23,909 Total Adjusted EBITDA $ 277,318 $ 271,649 $ 824,018 $ 772,864 Reconciliation of Net Income to Adjusted EBITDA: Net income $ 120,224 $ 160,270 $ 362,912 $ 439,746 Less: Net income attributable to noncontrolling interests (4,037 ) (3,896 ) (10,427 ) (11,803 ) Net income attributable to Buckeye Partners, L.P. 116,187 156,374 352,485 427,943 Add: Interest and debt expense 56,561 48,476 168,870 144,093 Income tax expense 448 308 1,709 896 Depreciation and amortization (1) 65,661 63,472 195,987 188,220 Non-cash unit-based compensation expense 8,176 8,853 25,756 22,912 Acquisition and transition expense (2) 1,447 309 3,275 479 Hurricane-related costs (3) 1,804 — 4,820 — Proportionate share of Adjusted EBITDA for the equity method investment in VTTI (4) 33,430 — 90,848 — Less: Amortization of unfavorable storage contracts (5) — (443 ) — (5,979 ) Gains on property damage recoveries (6) — (5,700 ) (4,621 ) (5,700 ) Earnings from the equity method investment in VTTI (4) (6,396 ) — (15,111 ) — Adjusted EBITDA $ 277,318 $ 271,649 $ 824,018 $ 772,864 (1) Includes 100% of the depreciation and amortization expense of $18.1 million and $18.5 million for Buckeye Texas for the three months ended September 30, 2017 and 2016 , respectively, and $54.1 million and $52.5 million for the nine months ended September 30, 2017 and 2016 , respectively. (2) Represents transaction, internal and third-party costs related to asset acquisition and integration. (3) Represents costs incurred at our BBH facility in the Bahamas, Yabucoa Terminal in Puerto Rico, Corpus Christi facilities in Texas, and certain terminals in Florida, as a result of Hurricanes Harvey, Irma, and Maria, which occurred in August and September 2017, as well as Hurricane Matthew, which occurred in October 2016, consisting of operating expenses and write-offs of damaged long-lived assets. (4) Due to the significance of our equity method investment in VTTI, effective January 1, 2017, we applied the definition of Adjusted EBITDA, covered in our description of Adjusted EBITDA, with respect to our proportionate share of VTTI’s Adjusted EBITDA. The calculation of our proportionate share of the reconciling items used to derive Adjusted EBITDA is based upon our 50% equity interest in VTTI, prior to adjustments related to noncontrolling interests in several of its subsidiaries and partnerships, which are immaterial. (5) Represents amortization of negative fair value allocated to certain unfavorable storage contracts acquired in connection with the BBH acquisition. (6) Represents gains on recoveries of property damages caused by third parties, primarily related to an allision with a ship dock at our terminal located in Pennsauken, New Jersey.

SUPPLEMENTAL CASH FLOW INFORMAT

SUPPLEMENTAL CASH FLOW INFORMATION	9 Months Ended
	Sep. 30, 2017
Supplemental Cash Flow Elements [Abstract]
SUPPLEMENTAL CASH FLOW INFORMATION	14. SUPPLEMENTAL CASH FLOW INFORMATION Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands): Nine Months Ended 2017 2016 Cash paid for interest (net of capitalized interest) $ 161,914 $ 141,140 Cash paid for income taxes 1,359 670 Capitalized interest 3,445 3,142 Liabilities related to capital projects outstanding at September 30, 2017 and 2016 of $51.0 million and $45.2 million , respectively, are not included under “Capital expenditures” within the unaudited condensed consolidated statements of cash flows.

ORGANIZATION AND BASIS OF PRE22

ORGANIZATION AND BASIS OF PRESENTATION (Policies)	9 Months Ended
	Sep. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Organization Buckeye Partners, L.P. is a publicly traded Delaware master limited partnership (“MLP”), and its limited partnership units representing limited partner interests (“LP Units”) are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “BPL.” Buckeye GP LLC (“Buckeye GP”) is our general partner. As used in these Notes to Unaudited Condensed Consolidated Financial Statements, “ we ,” “ us ,” “ our ” and “ Buckeye ” mean Buckeye Partners, L.P. and, where the context requires, includes our subsidiaries. We own and operate, or own a significant interest in, a diversified global network of integrated assets providing midstream logistic solutions, primarily consisting of the transportation, storage, processing and marketing of liquid petroleum products. We are one of the largest independent liquid petroleum products pipeline operators in the United States in terms of volumes delivered and miles of pipeline. We also use our service expertise to operate and/or maintain third-party pipelines and perform certain engineering and construction services for our customers. Our global terminal network, including through our interest in VTTI B.V. (“VTTI”), comprises active product terminals across our portfolio of pipelines, inland terminals and marine terminals located primarily in key petroleum logistics hubs in the East Coast, Midwest and Gulf Coast regions of the United States as well as in the Caribbean, Northwest Europe, the Middle East and Southeast Asia. Our global network of marine terminals enables us to facilitate global flows of crude oil and refined petroleum products, offering our customers connectivity between supply areas and market centers through some of the world’s most important bulk liquid storage and blending hubs. Our flagship marine terminal in The Bahamas, Buckeye Bahamas Hub Limited (“BBH”), is one of the largest marine crude oil and refined petroleum products storage facilities in the world and provides an array of logistics and blending services for the global flow of petroleum products. Our Gulf Coast regional hub, Buckeye Texas Partners LLC (“Buckeye Texas”), offers world-class marine terminalling, storage and processing capabilities. Through our 50% equity interest in VTTI, our global terminal network offers premier storage and marine terminalling services for petroleum product logistics in key international energy hubs. We are also a wholesale distributor of refined petroleum products in certain areas served by our pipelines and terminals.
Basis of Presentation and Principles of Consolidation	Basis of Presentation and Principles of Consolidation The unaudited condensed consolidated financial statements and the accompanying notes are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules of the U.S. Securities and Exchange Commission. Accordingly, our financial statements reflect all normal and recurring adjustments that are, in the opinion of management, necessary for a fair presentation of our results of operations for the interim periods. The unaudited condensed consolidated financial statements include the accounts of our subsidiaries controlled by us and variable interest entities of which we are the primary beneficiary. Intercompany transactions are eliminated in consolidation. We believe that the disclosures in these unaudited condensed consolidated financial statements are adequate to make the information presented not misleading. These interim financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2016 .
Recent Accounting Developments	Recent Accounting Developments Derivatives and Hedging . In August 2017, the Financial Accounting Standards Board (“FASB”) issued guidance which amends and simplifies existing guidance in order to improve the financial reporting of hedging relationships to better align risk management activities in financial statements and make targeted improvements to simplify the application of current guidance related to the assessment of hedge effectiveness. The amendments are effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early application permitted. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements. Modifications to Share-Based Payment Awards . In May 2017, the FASB issued guidance to clarify when changes in the terms or conditions of share-based payment awards must be accounted for as modifications under Topic 718. The guidance requires that entities apply modification accounting unless the award’s fair value, vesting conditions and classification as an equity or liability instrument are the same immediately before and after the change. The amendments are effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted. The amendments should be applied prospectively to awards modified on or after the adoption date. We expect to adopt this guidance on January 1, 2018, and it will be applied to modifications of our unit-based awards prospectively, if any. Retirement Benefits . In March 2017, the FASB issued guidance to amend the presentation of net periodic pension cost and net periodic postretirement benefit cost. The guidance requires that the service cost component of net periodic pension and postretirement benefit cost be presented in the same income statement line item as other employee compensation costs, while the other components are required to be presented separately within non-operating income. The guidance also allows only the service cost component to be eligible for capitalization when applicable. The amendments are effective for interim and annual periods beginning after December 15, 2017. The amendments should be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit in assets. We are currently evaluating the impact the adoption of this guidance will have on our consolidated financial statements. Revenue from Contracts with Customers . In May 2014, the FASB issued Accounting Standards Update No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which amended existing accounting standards for revenue recognition, including industry-specific requirements, and provides entities with a single revenue recognition model for recognizing revenue from contracts with customers. The core principle of ASU 2014-09 is that an entity should recognize revenue from contracts with customers when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Furthermore, additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. The two permitted transition methods under ASU 2014-09 are the full retrospective method, which would be applied to each prior reporting period presented and the cumulative effect of applying the standard would be recognized at the earliest period shown, or the modified retrospective method, in which the cumulative effect of applying the standard would be recognized at the date of initial application. In July 2015, the FASB deferred the effective date of ASU 2014-09 and is effective for annual and interim periods beginning after December 15, 2017, with early adoption permitted for annual and interim periods beginning after December 15, 2016. In 2016, the FASB issued accounting standards updates that amended several aspects of ASU 2014-09. We continue to evaluate the provisions of the standard through our implementation work team, consisting of representatives from all of our business segments, and to assess and implement changes to business processes, systems and controls, as necessary. In addition, we have implemented training on the new standard’s revenue recognition model and are continuing our contract review and documentation. We will adopt this guidance on January 1, 2018, and we are currently evaluating the impact that it will have on our consolidated financial statements, including our disclosures, under the elected modified retrospective transition method. To date, we have not identified any customer arrangements which would require a significant change to the timing of our revenue recognition, although our analysis is not yet complete. Equity-Based Compensation . In March 2016, the FASB issued guidance to simplify several aspects of the accounting for employee equity-based payment transactions, including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification in the statement of cash flows and classification of awards as liabilities or equity. The guidance was effective for annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods, with early adoption permitted. Amendments related to the timing of when excess tax benefits are recognized, statutory withholding requirements and forfeitures were to be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows were to be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement were to be applied prospectively. Amendments related to the presentation of excess tax benefits on the statement of cash flows were to be applied using either a prospective transition method or a retrospective transition method. We adopted this guidance as of January 1, 2017 and did not recognize a retrospective transition adjustment. The adoption of this guidance did not have a material impact on our consolidated financial statements or on our disclosures.

ACQUISITIONS (Tables)

ACQUISITIONS (Tables)	9 Months Ended
	Sep. 30, 2017
Indianola Pipeline
Business Acquisition [Line Items]
Schedule of purchase price allocated to tangible and intangible assets acquired and liabilities assumed	The purchase price has been allocated to tangible and intangible assets acquired as follows (in thousands): Inventories $ 1,554 Property, plant and equipment 16,713 Goodwill 7,758 Allocated purchase price $ 26,025

INVENTORIES (Tables)

INVENTORIES (Tables)	9 Months Ended
	Sep. 30, 2017
Inventory Disclosure [Abstract]
Schedule of inventory	Our inventory amounts were as follows at the dates indicated (in thousands): September 30, December 31, Liquid petroleum products (1) $ 210,747 $ 337,424 Materials and supplies 22,666 19,379 Total inventories $ 233,413 $ 356,803 (1) Ending inventory was 122.3 million and 198.2 million gallons of liquid petroleum products as of September 30, 2017 and December 31, 2016 , respectively.

PREPAID AND OTHER CURRENT ASS25

PREPAID AND OTHER CURRENT ASSETS (Tables)	9 Months Ended
	Sep. 30, 2017
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Schedule of prepaid and other current assets	Prepaid and other current assets consist of the following at the dates indicated (in thousands): September 30, December 31, Prepaid insurance $ 13,446 $ 7,609 Margin deposits 8,184 43,912 Unbilled revenue 9,003 1,615 Prepaid taxes 5,212 7,357 Vendor prepayments 767 1,863 Other 3,941 4,180 Total prepaid and other current assets $ 40,553 $ 66,536

EQUITY INVESTMENTS (Tables)

EQUITY INVESTMENTS (Tables)	9 Months Ended
	Sep. 30, 2017
Equity Method Investments and Joint Ventures [Abstract]
Earnings (losses) from equity investments	The following table presents earnings from equity investments for the periods indicated (in thousands): Three Months Ended Nine Months Ended Segment 2017 2016 2017 2016 VTTI B.V. (1) Global Marine Terminals $ 6,396 $ — $ 15,111 $ — West Shore Pipe Line Company Domestic Pipelines & Terminals 1,772 1,784 4,913 5,680 Muskegon Pipeline LLC Domestic Pipelines & Terminals 501 544 1,303 1,340 Transport4, LLC Domestic Pipelines & Terminals 206 204 650 577 South Portland Terminal LLC Domestic Pipelines & Terminals 357 369 733 862 Total earnings from equity investments $ 9,232 $ 2,901 $ 22,710 $ 8,459 (1) We acquired an indirect 50% equity interest in VTTI in January 2017. For additional information, see Note 2 .
Summary of combined income statement data for equity method investments	Summarized combined income statement data for our equity method investments are as follows for the periods indicated (amounts represent 100% of investee income statement data in thousands): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Revenue $ 143,946 $ 22,831 $ 403,985 $ 65,877 Operating income 52,766 12,805 138,195 35,411 Net income 30,874 8,663 84,807 23,986 Net income attributable to investee 23,565 8,663 63,347 23,986

DERIVATIVE INSTRUMENTS AND HE27

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	9 Months Ended
	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of commodity derivative instruments outstanding	The following table summarizes our commodity derivative instruments outstanding at September 30, 2017 (amounts in thousands of gallons): Volume (1) Derivative Purpose Current Long-Term Derivatives NOT designated as hedging instruments: Physical fixed-price derivative contracts 7,115 1,110 Physical index derivative contracts 35,385 — Futures contracts for refined petroleum products 241 6,090 Hedge Type Derivatives designated as hedging instruments: Physical fixed-price derivative contracts 1,050 — Cash Flow Hedge Cash flow hedge futures contracts 13,104 8,400 Cash Flow Hedge Futures contracts for refined petroleum products 100,632 4,494 Fair Value Hedge (1) Volume represents absolute value of net notional volume position. All volumes represent net short positions, except for the physical fixed-price derivative contracts designated as a cash flow hedge.
Fair value of each classification of derivative instrument and their location in the unaudited consolidated balance sheet	The following table sets forth the fair value of each classification of derivative instruments and the locations of the derivative instruments on our unaudited condensed consolidated balance sheets at the dates indicated (in thousands): September 30, 2017 Derivatives NOT Designated as Hedging Instruments Derivatives Designated as Hedging Instruments Derivative Carrying Value Netting Balance Sheet Adjustment (1) Net Total Physical fixed-price derivative contracts $ 816 $ — $ 816 $ (95 ) $ 721 Physical index derivative contracts 226 — 226 (2 ) 224 Interest rates derivatives — 49,939 49,939 — 49,939 Total current derivative assets 1,042 49,939 50,981 (97 ) 50,884 Physical fixed-price derivative contracts 2 — 2 — 2 Total non-current derivative assets 2 — 2 — 2 Physical fixed-price derivative contracts (3,558 ) (104 ) (3,662 ) 95 (3,567 ) Physical index derivative contracts (3 ) — (3 ) 2 (1 ) Total current derivative liabilities (3,561 ) (104 ) (3,665 ) 97 (3,568 ) Physical fixed-price derivative contracts (84 ) — (84 ) — (84 ) Total non-current derivative liabilities (84 ) — (84 ) — (84 ) Net derivative (liabilities) assets $ (2,601 ) $ 49,835 $ 47,234 $ — $ 47,234 (1) Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists. Futures contracts are subject to settlement through margin requirements and are additionally presented on a net basis. December 31, 2016 Derivatives NOT Designated as Hedging Instruments Derivatives Designated as Hedging Instruments Derivative Carrying Value Netting Balance Sheet Adjustment (1) Net Total Physical fixed-price derivative contracts $ 1,499 $ — $ 1,499 $ (306 ) $ 1,193 Physical index derivative contracts 334 — 334 (1 ) 333 Futures contracts for refined products 51,431 21 51,452 (51,452 ) — Total current derivative assets 53,264 21 53,285 (51,759 ) 1,526 Physical fixed-price derivative contracts 164 — 164 (5 ) 159 Futures contracts for refined products 226 — 226 (226 ) — Interest rates derivatives — 62,609 62,609 — 62,609 Total non-current derivative assets 390 62,609 62,999 (231 ) 62,768 Physical fixed-price derivative contracts (4,517 ) — (4,517 ) 306 (4,211 ) Physical index derivative contracts (1 ) — (1 ) 1 — Futures contracts for refined products (57,828 ) (15,685 ) (73,513 ) 51,452 (22,061 ) Total current derivative liabilities (62,346 ) (15,685 ) (78,031 ) 51,759 (26,272 ) Physical fixed-price derivative contracts (61 ) — (61 ) 5 (56 ) Futures contracts for refined products (4,384 ) — (4,384 ) 226 (4,158 ) Total non-current derivative liabilities (4,445 ) — (4,445 ) 231 (4,214 ) Net derivative (liabilities) assets $ (13,137 ) $ 46,945 $ 33,808 $ — $ 33,808 (1) Amounts represent the netting of physical fixed and index contracts’ assets and liabilities when a legal right of offset exists. Futures contracts are subject to settlement through margin requirements and are additionally presented on a net basis.
Gains and losses on derivative instruments recognized in income	The gains and losses on our derivative instruments recognized in income were as follows for the periods indicated (in thousands): Three Months Ended Nine Months Ended Location 2017 2016 2017 2016 Derivatives NOT designated as hedging instruments: Physical fixed-price derivative contracts Product sales $ (7,209 ) $ 301 $ (257 ) $ (7,263 ) Physical index derivative contracts Product sales 57 142 58 130 Physical fixed-price derivative contracts Cost of product sales 1,462 479 1,380 7,965 Physical index derivative contracts Cost of product sales 115 30 453 193 Futures contracts for refined products Cost of product sales 15,861 (307 ) 15,061 4,326 Derivatives designated as fair value hedging instruments: Futures contracts for refined products Cost of product sales $ (51,093 ) $ (635 ) $ 1,758 $ (27,590 ) Physical inventory - hedged items Cost of product sales 48,236 3,620 7,536 43,627 Ineffectiveness excluding the time value component on fair value hedging instruments: Fair value hedge ineffectiveness (excluding time value) Cost of product sales $ (3,299 ) $ (4,262 ) $ (5,929 ) $ (4,275 ) Time value excluded from hedge assessment Cost of product sales 442 7,247 15,223 20,312 Net (loss) gain in income $ (2,857 ) $ 2,985 $ 9,294 $ 16,037
(Loss) gain recognized in OCI and gains (losses) reclassified from AOCI to income	The change in value recognized in OCI and the gains and losses reclassified from AOCI to income attributable to our derivative instruments designated as cash flow hedges were as follows for the periods indicated (in thousands): (Loss) Gain Recognized in OCI on Derivatives for the Three Months Ended Nine Months Ended 2017 2016 2017 2016 Derivatives designated as cash flow hedging instruments: Interest rate contracts $ (2,207 ) $ 1,052 $ (12,670 ) $ 1,052 Commodity derivatives (3,557 ) — 675 — Total $ (5,764 ) $ 1,052 $ (11,995 ) $ 1,052 (Loss) Gain Reclassified from AOCI to Income (Effective Portion) for the Three Months Ended Nine Months Ended Location 2017 2016 2017 2016 Derivatives designated as cash flow hedging instruments: Interest rate contracts Interest and debt expense $ (3,038 ) $ (3,037 ) $ (9,113 ) $ (9,112 ) Commodity derivatives Product Sales — — — 1,266 Total $ (3,038 ) $ (3,037 ) $ (9,113 ) $ (7,846 )

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	9 Months Ended
	Sep. 30, 2017
Fair Value Disclosures [Abstract]
Financial assets and liabilities measured at fair value on a recurring basis	The following table sets forth financial assets and liabilities measured at fair value on a recurring basis, as of the measurement dates indicated, and the basis for that measurement, by level within the fair value hierarchy (in thousands): September 30, 2017 December 31, 2016 Level 1 Level 2 Level 1 Level 2 Financial assets: Physical fixed-price derivative contracts $ — $ 818 $ — $ 1,352 Physical index derivative contracts — 226 — 333 Interest rate derivatives — 49,939 — 62,609 Financial liabilities: Physical fixed-price derivative contracts — (3,746 ) — (4,267 ) Physical index derivative contracts — (3 ) — — Futures contracts for refined products — — (26,219 ) — Fair value $ — $ 47,234 $ (26,219 ) $ 60,027
Carrying value and fair value using level 2 inputs of debt	The carrying value and fair value of our debt, using Level 2 input values, were as follows at the dates indicated (in thousands): September 30, 2017 December 31, 2016 Carrying Amount Fair Value Carrying Amount Fair Value Fixed-rate debt $ 3,846,426 $ 4,016,825 $ 3,967,695 $ 4,083,488 Variable-rate debt 932,619 933,010 250,000 250,000 Total debt $ 4,779,045 $ 4,949,835 $ 4,217,695 $ 4,333,488

UNIT-BASED COMPENSATION PLANS (

UNIT-BASED COMPENSATION PLANS (Tables)	9 Months Ended
	Sep. 30, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Awards activity under the LTIP	The following table sets forth the LTIP activity for the periods indicated (in thousands, except per unit amounts): Number of LP Units Weighted Average Grant Date Fair Value per LP Unit (1) Unvested at January 1, 2017 1,296 $ 63.54 Granted (2) 547 69.93 Performance adjustment (3) 32 71.50 Vested (333 ) 70.30 Forfeited (32 ) 64.48 Unvested at September 30, 2017 1,510 $ 64.47 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per LP Unit for forfeited and vested awards is determined before an allowance for forfeitures. (2) Includes both phantom and performance awards. Performance awards are granted at a target amount but, depending on our performance during the vesting period with respect to certain pre-established goals, the number of LP Units issued upon vesting of such performance awards can be greater or less than the target amount. (3) Represents the LP Units issued in excess of target amounts for performance awards that vested during the nine months ended September 30, 2017 as a result of our above target performance with respect to applicable performance goals.
Summary of changes in options outstanding	The following is a summary of the changes in the options outstanding (all of which are vested) under the Option Plan for the periods indicated (in thousands, except per unit amounts): Number of LP Units Weighted Average Strike Price per LP Unit Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (1) Outstanding at January 1, 2017 10 $ 50.36 0.1 $ 151 Exercised (10 ) — Outstanding at September 30, 2017 — — — $ — Exercisable at September 30, 2017 — $ — — $ — (1) Aggregate intrinsic value reflects fully vested LP Unit options at the date indicated. Intrinsic value is determined by calculating the difference between our closing LP Unit price on the last trading day in September 2017 and the exercise price, multiplied by the number of exercisable, in-the-money options.

PARTNERS' CAPITAL AND DISTRIB30

PARTNERS' CAPITAL AND DISTRIBUTIONS (Tables)	9 Months Ended
	Sep. 30, 2017
Equity [Abstract]
Summary of changes in LP units outstanding	The following is a summary of changes in Buckeye ’ s outstanding LP Units for the periods indicated (in thousands): Limited Partners LP Units outstanding at January 1, 2017 140,264 LP Units issued pursuant to the Option Plan (1) 10 LP Units issued pursuant to the LTIP (1) 209 Issuance of LP Units through the Equity Distribution Agreement 6,159 LP Units outstanding at September 30, 2017 146,642 (1) The number of LP Units issued represents issuance net of tax withholding.

EARNINGS PER UNIT (Tables)

EARNINGS PER UNIT (Tables)	9 Months Ended
	Sep. 30, 2017
Earnings Per Share [Abstract]
Reconciliation of weighted average units outstanding used in computing basic and diluted earnings per unit	The following table is a reconciliation of the weighted average units outstanding used in computing the basic and diluted earnings per unit for the periods indicated (in thousands, except per unit amounts): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Net income attributable to Buckeye Partners, L.P. $ 116,187 $ 156,374 $ 352,485 $ 427,943 Basic: Weighted average units outstanding - basic 142,088 131,113 141,104 130,439 Earnings per unit - basic $ 0.82 $ 1.19 $ 2.50 $ 3.28 Diluted: Weighted average units outstanding - basic 142,088 131,113 141,104 130,439 Dilutive effect of LP Unit options and LTIP awards granted 730 827 677 637 Weighted average units outstanding - diluted 142,818 131,940 141,781 131,076 Earnings per unit - diluted $ 0.81 $ 1.19 $ 2.49 $ 3.26

BUSINESS SEGMENTS (Tables)

BUSINESS SEGMENTS (Tables)	9 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Summary of revenue by each segment	The following table summarizes revenue by each segment for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Revenue: Domestic Pipelines & Terminals $ 254,277 $ 265,036 $ 761,438 $ 752,968 Global Marine Terminals 155,281 170,072 487,613 509,653 Merchant Services 526,844 344,041 1,498,438 1,103,186 Intersegment (13,783 ) (12,544 ) (45,396 ) (41,486 ) Total revenue $ 922,619 $ 766,605 $ 2,702,093 $ 2,324,321
Summary of revenue for continuing operations by major geographic area	The following table summarizes revenue by major geographic area for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Revenue: United States $ 855,795 $ 683,850 $ 2,474,562 $ 2,072,893 International 66,824 82,755 227,531 251,428 Total revenue $ 922,619 $ 766,605 $ 2,702,093 $ 2,324,321
Adjusted EBITDA by segment and Reconciliation of Net Income to Adjusted EBITDA	The following tables present Adjusted EBITDA by segment and on a consolidated basis and a reconciliation of net income, which is the most comparable financial measure under GAAP, to Adjusted EBITDA for the periods indicated (in thousands): Three Months Ended Nine Months Ended 2017 2016 2017 2016 Adjusted EBITDA: Domestic Pipelines & Terminals $ 138,880 $ 152,785 $ 413,710 $ 423,245 Global Marine Terminals 128,696 110,705 391,084 325,710 Merchant Services 9,742 8,159 19,224 23,909 Total Adjusted EBITDA $ 277,318 $ 271,649 $ 824,018 $ 772,864 Reconciliation of Net Income to Adjusted EBITDA: Net income $ 120,224 $ 160,270 $ 362,912 $ 439,746 Less: Net income attributable to noncontrolling interests (4,037 ) (3,896 ) (10,427 ) (11,803 ) Net income attributable to Buckeye Partners, L.P. 116,187 156,374 352,485 427,943 Add: Interest and debt expense 56,561 48,476 168,870 144,093 Income tax expense 448 308 1,709 896 Depreciation and amortization (1) 65,661 63,472 195,987 188,220 Non-cash unit-based compensation expense 8,176 8,853 25,756 22,912 Acquisition and transition expense (2) 1,447 309 3,275 479 Hurricane-related costs (3) 1,804 — 4,820 — Proportionate share of Adjusted EBITDA for the equity method investment in VTTI (4) 33,430 — 90,848 — Less: Amortization of unfavorable storage contracts (5) — (443 ) — (5,979 ) Gains on property damage recoveries (6) — (5,700 ) (4,621 ) (5,700 ) Earnings from the equity method investment in VTTI (4) (6,396 ) — (15,111 ) — Adjusted EBITDA $ 277,318 $ 271,649 $ 824,018 $ 772,864 (1) Includes 100% of the depreciation and amortization expense of $18.1 million and $18.5 million for Buckeye Texas for the three months ended September 30, 2017 and 2016 , respectively, and $54.1 million and $52.5 million for the nine months ended September 30, 2017 and 2016 , respectively. (2) Represents transaction, internal and third-party costs related to asset acquisition and integration. (3) Represents costs incurred at our BBH facility in the Bahamas, Yabucoa Terminal in Puerto Rico, Corpus Christi facilities in Texas, and certain terminals in Florida, as a result of Hurricanes Harvey, Irma, and Maria, which occurred in August and September 2017, as well as Hurricane Matthew, which occurred in October 2016, consisting of operating expenses and write-offs of damaged long-lived assets. (4) Due to the significance of our equity method investment in VTTI, effective January 1, 2017, we applied the definition of Adjusted EBITDA, covered in our description of Adjusted EBITDA, with respect to our proportionate share of VTTI’s Adjusted EBITDA. The calculation of our proportionate share of the reconciling items used to derive Adjusted EBITDA is based upon our 50% equity interest in VTTI, prior to adjustments related to noncontrolling interests in several of its subsidiaries and partnerships, which are immaterial. (5) Represents amortization of negative fair value allocated to certain unfavorable storage contracts acquired in connection with the BBH acquisition. (6) Represents gains on recoveries of property damages caused by third parties, primarily related to an allision with a ship dock at our terminal located in Pennsauken, New Jersey.

SUPPLEMENTAL CASH FLOW INFORM33

SUPPLEMENTAL CASH FLOW INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2017
Supplemental Cash Flow Elements [Abstract]
Supplemental cash flows and non-cash transactions	Supplemental cash flows and non-cash transactions were as follows for the periods indicated (in thousands): Nine Months Ended 2017 2016 Cash paid for interest (net of capitalized interest) $ 161,914 $ 141,140 Cash paid for income taxes 1,359 670 Capitalized interest 3,445 3,142

ORGANIZATION AND BASIS OF PRE34

ORGANIZATION AND BASIS OF PRESENTATION - Additional Information (Details)	Sep. 30, 2017	Jan. 31, 2017
VTTI B.V.
Investment [Line Items]
Ownership percentage	50.00%	50.00%

ACQUISITIONS - Narrative (Detai

ACQUISITIONS - Narrative (Details) $ in Thousands, bbl in Millions	1 Months Ended
	Sep. 30, 2017USD ($)	Jan. 31, 2017USD ($)continentterminalbbl	Aug. 31, 2016USD ($)	Dec. 31, 2016USD ($)
Business Acquisition [Line Items]
Goodwill	$ 1,004,545			$ 1,004,545
Indianola Pipeline
Business Acquisition [Line Items]
Consideration for business acquisition			$ 26,000
Goodwill			$ 7,758
VTTI Acquisition
Business Acquisition [Line Items]
Percentage of interest acquired		50.00%
Cash consideration		$ 1,150,000
VTTI MLP
Business Acquisition [Line Items]
Percentage of cash consideration	50.00%
VTTI B.V.
Business Acquisition [Line Items]
Product storage capacity (in bbl) | bbl		58
Number of terminals | terminal		15
Number of continents | continent		5
Proceeds from capital contribution	$ 236,800
VTTI B.V. | VTTI MLP
Business Acquisition [Line Items]
Cash consideration	$ 473,600
VTTI B.V.
Business Acquisition [Line Items]
Excess net investment		$ 583,300
Excess fair value of PPE and intangible assets		$ 233,000
Useful life of assets		28 years
Goodwill		$ 350,300

ACQUISITIONS - Purchase Price A

ACQUISITIONS - Purchase Price Allocation to Tangible and Intangible Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016	Aug. 31, 2016
Business Acquisition [Line Items]
Goodwill	$ 1,004,545	$ 1,004,545
Indianola Pipeline
Business Acquisition [Line Items]
Inventories			$ 1,554
Property, plant and equipment			16,713
Goodwill			7,758
Allocated purchase price			$ 26,025

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Environmental Contingencies (Details) - Environmental remediation unrelated to claims and legal proceedings - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure
Environmental remediation liabilities	$ 41.9	$ 44.3
Receivables related to environmental remediation expenditures covered by insurance or third party claims	$ 5.7	$ 7.2

INVENTORIES (Details)

INVENTORIES (Details) $ in Thousands, gal in Millions	Sep. 30, 2017USD ($)gal	Dec. 31, 2016USD ($)gal
Inventory Disclosure [Abstract]
Liquid petroleum products	$ 210,747	$ 337,424
Materials and supplies	22,666	19,379
Total inventories	$ 233,413	$ 356,803
Refined petroleum products (in gallons) | gal	122.3	198.2
Percentage of hedged refined petroleum products inventory	86.00%	88.00%

PREPAID AND OTHER CURRENT ASS39

PREPAID AND OTHER CURRENT ASSETS (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid insurance	$ 13,446	$ 7,609
Margin deposits	8,184	43,912
Unbilled revenue	9,003	1,615
Prepaid taxes	5,212	7,357
Vendor prepayments	767	1,863
Other	3,941	4,180
Total prepaid and other current assets	$ 40,553	$ 66,536

EQUITY INVESTMENTS - Equity Inv

EQUITY INVESTMENTS - Equity Investments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Jan. 31, 2017
Equity investments
Total earnings from equity investments	$ 9,232	$ 2,901	$ 22,710	$ 8,459
VTTI B.V.
Equity investments
Ownership percentage	50.00%		50.00%		50.00%
Global Marine Terminals | VTTI B.V.
Equity investments
Total earnings from equity investments	$ 6,396	0	$ 15,111	0
Domestic Pipelines & Terminals | West Shore Pipe Line Company
Equity investments
Total earnings from equity investments	1,772	1,784	4,913	5,680
Domestic Pipelines & Terminals | Muskegon Pipeline LLC
Equity investments
Total earnings from equity investments	501	544	1,303	1,340
Domestic Pipelines & Terminals | Transport4, LLC
Equity investments
Total earnings from equity investments	206	204	650	577
Domestic Pipelines & Terminals | South Portland Terminal LLC
Equity investments
Total earnings from equity investments	$ 357	$ 369	$ 733	$ 862

EQUITY INVESTMENTS - Income Fro

EQUITY INVESTMENTS - Income From Equity Method Investments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Equity Method Investments and Joint Ventures [Abstract]
Representation of investee financial information in the summarized equity method investments (as a percent)			100.00%
INCOME STATEMENT DATA:
Revenue	$ 143,946	$ 22,831	$ 403,985	$ 65,877
Operating income	52,766	12,805	138,195	35,411
Net income	30,874	8,663	84,807	23,986
Net income attributable to investee	$ 23,565	$ 8,663	$ 63,347	$ 23,986

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($)	1 Months Ended
	Jul. 31, 2017	Sep. 30, 2017
Revolving Credit Facility | Line of Credit
Debt instrument
Amount of maximum borrowing capacity		$ 1,500,000,000
Additional borrowing capacity		$ 814,600,000
5.125% Notes
Debt instrument
Principal amount repaid	$ 125,000,000
Accrued interest amount repaid	$ 3,200,000
Interest rate percentage	5.125%
6.050% Notes Due January 2018
Debt instrument
Interest rate percentage		6.05%
Face amount		$ 300,000,000

DERIVATIVE INSTRUMENTS AND HE43

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Additional Information (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)instrument
Interest Rate Swap Entered Into In Anticipation of Debt Due January 2018
Derivative [Line Items]
Number of instruments entered into | instrument					7
Notional amount					$ 350,000,000
Interest Rate Swap Entered Into In Anticipation of Debt Due November 2018
Derivative [Line Items]
Number of instruments entered into | instrument					11
Notional amount					$ 500,000,000
Settled Forward-Starting Interest Rate Swaps
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months			$ (9,800,000)
Interest rate contracts
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months			(11,500,000)
Forward-Starting Interest Rate Swaps
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months			1,700,000
Commodity derivatives
Derivative [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months			700,000
6.050% Notes Due January 2018
Derivative [Line Items]
Face amount	$ 300,000,000		$ 300,000,000
Interest rate percentage	6.05%		6.05%
6.050% Notes Due January 2018 | Notes Payable
Derivative [Line Items]
Face amount					$ 300,000,000
Interest rate percentage					6.05%
2.650% Notes Due November 2018 | Notes Payable
Derivative [Line Items]
Face amount					$ 400,000,000
Interest rate percentage					2.65%
Cash Flow Hedge
Derivative [Line Items]
Loss recognized in OCI on derivatives	$ 5,764,000	$ (1,052,000)	$ 11,995,000	$ (1,052,000)
Cash Flow Hedge | Interest rate contracts
Derivative [Line Items]
Loss recognized in OCI on derivatives	2,207,000	(1,052,000)	12,670,000	(1,052,000)
Cash Flow Hedge | Commodity derivatives
Derivative [Line Items]
Loss recognized in OCI on derivatives	$ 3,557,000	$ 0	$ (675,000)	$ 0

DERIVATIVE INSTRUMENTS AND HE44

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Commodity Derivative Instruments (Details) gal in Thousands	9 Months Ended
	Sep. 30, 2017gal
Derivatives NOT Designated as Hedging Instruments | Physical fixed-price derivative contracts | Current
Derivative Instruments And Hedging Activities
Volume (in gallons)	7,115
Derivatives NOT Designated as Hedging Instruments | Physical fixed-price derivative contracts | Long-Term
Derivative Instruments And Hedging Activities
Volume (in gallons)	1,110
Derivatives NOT Designated as Hedging Instruments | Physical index derivative contracts | Current
Derivative Instruments And Hedging Activities
Volume (in gallons)	35,385
Derivatives NOT Designated as Hedging Instruments | Physical index derivative contracts | Long-Term
Derivative Instruments And Hedging Activities
Volume (in gallons)	0
Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products | Current
Derivative Instruments And Hedging Activities
Volume (in gallons)	241
Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products | Long-Term
Derivative Instruments And Hedging Activities
Volume (in gallons)	6,090
Derivatives Designated as Hedging Instruments | Cash Flow Hedge | Physical fixed-price derivative contracts | Current
Derivative Instruments And Hedging Activities
Volume (in gallons)	1,050
Derivatives Designated as Hedging Instruments | Cash Flow Hedge | Physical fixed-price derivative contracts | Long-Term
Derivative Instruments And Hedging Activities
Volume (in gallons)	0
Derivatives Designated as Hedging Instruments | Cash Flow Hedge | Cash flow hedge futures contracts | Current
Derivative Instruments And Hedging Activities
Volume (in gallons)	13,104
Derivatives Designated as Hedging Instruments | Cash Flow Hedge | Cash flow hedge futures contracts | Long-Term
Derivative Instruments And Hedging Activities
Volume (in gallons)	8,400
Derivatives Designated as Hedging Instruments | Fair Value Hedge | Futures contracts for refined petroleum products | Current
Derivative Instruments And Hedging Activities
Volume (in gallons)	100,632
Derivatives Designated as Hedging Instruments | Fair Value Hedge | Futures contracts for refined petroleum products | Long-Term
Derivative Instruments And Hedging Activities
Volume (in gallons)	4,494

DERIVATIVE INSTRUMENTS AND HE45

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Fair Value of Each Classification of Derivative Instrument (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Derivatives, Fair Value
Fair value	$ 47,234	$ 33,808
Netting balance sheet adjustment	0	0
Net Total
Derivatives, Fair Value
Fair value	47,234	33,808
Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(2,601)	(13,137)
Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	49,835	46,945
Total current derivative assets
Derivatives, Fair Value
Fair value	50,981	53,285
Netting balance sheet adjustment	(97)	(51,759)
Total current derivative assets | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	816	1,499
Netting balance sheet adjustment	(95)	(306)
Total current derivative assets | Physical index derivative contracts
Derivatives, Fair Value
Fair value	226	334
Netting balance sheet adjustment	(2)	(1)
Total current derivative assets | Interest rate derivatives
Derivatives, Fair Value
Fair value	49,939
Netting balance sheet adjustment	0
Total current derivative assets | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		51,452
Netting balance sheet adjustment		(51,452)
Total current derivative assets | Net Total
Derivatives, Fair Value
Fair value	50,884	1,526
Total current derivative assets | Net Total | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	721	1,193
Total current derivative assets | Net Total | Physical index derivative contracts
Derivatives, Fair Value
Fair value	224	333
Total current derivative assets | Net Total | Interest rate derivatives
Derivatives, Fair Value
Fair value	49,939
Total current derivative assets | Net Total | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		0
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	1,042	53,264
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	816	1,499
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments | Physical index derivative contracts
Derivatives, Fair Value
Fair value	226	334
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments | Interest rate derivatives
Derivatives, Fair Value
Fair value	0
Total current derivative assets | Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		51,431
Total current derivative assets | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	49,939	21
Total current derivative assets | Derivatives Designated as Hedging Instruments | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	0	0
Total current derivative assets | Derivatives Designated as Hedging Instruments | Physical index derivative contracts
Derivatives, Fair Value
Fair value	0	0
Total current derivative assets | Derivatives Designated as Hedging Instruments | Interest rate derivatives
Derivatives, Fair Value
Fair value	49,939
Total current derivative assets | Derivatives Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		21
Total non-current derivative assets
Derivatives, Fair Value
Fair value	2	62,999
Netting balance sheet adjustment	0	(231)
Total non-current derivative assets | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	2	164
Netting balance sheet adjustment	0	(5)
Total non-current derivative assets | Interest rate derivatives
Derivatives, Fair Value
Fair value		62,609
Netting balance sheet adjustment		0
Total non-current derivative assets | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		226
Netting balance sheet adjustment		(226)
Total non-current derivative assets | Net Total
Derivatives, Fair Value
Fair value	2	62,768
Total non-current derivative assets | Net Total | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	2	159
Total non-current derivative assets | Net Total | Interest rate derivatives
Derivatives, Fair Value
Fair value		62,609
Total non-current derivative assets | Net Total | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		0
Total non-current derivative assets | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	2	390
Total non-current derivative assets | Derivatives NOT Designated as Hedging Instruments | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	2	164
Total non-current derivative assets | Derivatives NOT Designated as Hedging Instruments | Interest rate derivatives
Derivatives, Fair Value
Fair value		0
Total non-current derivative assets | Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		226
Total non-current derivative assets | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	0	62,609
Total non-current derivative assets | Derivatives Designated as Hedging Instruments | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	0	0
Total non-current derivative assets | Derivatives Designated as Hedging Instruments | Interest rate derivatives
Derivatives, Fair Value
Fair value		62,609
Total non-current derivative assets | Derivatives Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		0
Total current derivative liabilities
Derivatives, Fair Value
Fair value	(3,665)	(78,031)
Netting balance sheet adjustment	97	51,759
Total current derivative liabilities | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	(3,662)	(4,517)
Netting balance sheet adjustment	95	306
Total current derivative liabilities | Physical index derivative contracts
Derivatives, Fair Value
Fair value	(3)	(1)
Netting balance sheet adjustment	2	1
Total current derivative liabilities | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		(73,513)
Netting balance sheet adjustment		51,452
Total current derivative liabilities | Net Total
Derivatives, Fair Value
Fair value	(3,568)	(26,272)
Total current derivative liabilities | Net Total | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	(3,567)	(4,211)
Total current derivative liabilities | Net Total | Physical index derivative contracts
Derivatives, Fair Value
Fair value	(1)	0
Total current derivative liabilities | Net Total | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		(22,061)
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(3,561)	(62,346)
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	(3,558)	(4,517)
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Physical index derivative contracts
Derivatives, Fair Value
Fair value	(3)	(1)
Total current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		(57,828)
Total current derivative liabilities | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(104)	(15,685)
Total current derivative liabilities | Derivatives Designated as Hedging Instruments | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	(104)	0
Total current derivative liabilities | Derivatives Designated as Hedging Instruments | Physical index derivative contracts
Derivatives, Fair Value
Fair value	0	0
Total current derivative liabilities | Derivatives Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		(15,685)
Total non-current derivative liabilities
Derivatives, Fair Value
Fair value	(84)	(4,445)
Netting balance sheet adjustment	0	231
Total non-current derivative liabilities | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	(84)	(61)
Netting balance sheet adjustment	0	5
Total non-current derivative liabilities | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		(4,384)
Netting balance sheet adjustment		226
Total non-current derivative liabilities | Net Total
Derivatives, Fair Value
Fair value	(84)	(4,214)
Total non-current derivative liabilities | Net Total | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	(84)	(56)
Total non-current derivative liabilities | Net Total | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		(4,158)
Total non-current derivative liabilities | Derivatives NOT Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	(84)	(4,445)
Total non-current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	(84)	(61)
Total non-current derivative liabilities | Derivatives NOT Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		(4,384)
Total non-current derivative liabilities | Derivatives Designated as Hedging Instruments
Derivatives, Fair Value
Fair value	0	0
Total non-current derivative liabilities | Derivatives Designated as Hedging Instruments | Physical fixed-price derivative contracts
Derivatives, Fair Value
Fair value	$ 0	0
Total non-current derivative liabilities | Derivatives Designated as Hedging Instruments | Futures contracts for refined petroleum products
Derivatives, Fair Value
Fair value		$ 0

DERIVATIVE INSTRUMENTS AND HE46

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Gains and Losses on Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Hedge Ineffectiveness
Ineffectiveness excluding the time value component on fair value hedging instruments:
Net (loss) gain in income	$ (2,857)	$ 2,985	$ 9,294	$ 16,037
Derivatives NOT Designated as Hedging Instruments | Product sales | Physical fixed-price derivative contracts
Derivatives NOT designated as hedging instruments:
Gains (losses) on derivative instruments recognized in income	(7,209)	301	(257)	(7,263)
Derivatives NOT Designated as Hedging Instruments | Product sales | Physical index derivative contracts
Derivatives NOT designated as hedging instruments:
Gains (losses) on derivative instruments recognized in income	57	142	58	130
Derivatives NOT Designated as Hedging Instruments | Cost of product sales | Physical fixed-price derivative contracts
Derivatives NOT designated as hedging instruments:
Gains (losses) on derivative instruments recognized in income	1,462	479	1,380	7,965
Derivatives NOT Designated as Hedging Instruments | Cost of product sales | Physical index derivative contracts
Derivatives NOT designated as hedging instruments:
Gains (losses) on derivative instruments recognized in income	115	30	453	193
Derivatives NOT Designated as Hedging Instruments | Cost of product sales | Futures contracts for refined products
Derivatives NOT designated as hedging instruments:
Gains (losses) on derivative instruments recognized in income	15,861	(307)	15,061	4,326
Derivatives Designated as Hedging Instruments | Cost of product sales | Hedge Ineffectiveness
Ineffectiveness excluding the time value component on fair value hedging instruments:
Fair value hedge ineffectiveness (excluding time value)	(3,299)	(4,262)	(5,929)	(4,275)
Time value excluded from hedge assessment	442	7,247	15,223	20,312
Derivatives Designated as Hedging Instruments | Cost of product sales | Futures contracts for refined products
Derivatives designated as fair value hedging instruments:
Futures contracts for refined products	(51,093)	(635)	1,758	(27,590)
Derivatives Designated as Hedging Instruments | Cost of product sales | Physical inventory - hedged items
Derivatives designated as fair value hedging instruments:
Physical inventory - hedged items	$ 48,236	$ 3,620	$ 7,536	$ 43,627

DERIVATIVE INSTRUMENTS AND HE47

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - Changes in Value Recognized in OCI (Details) - Cash Flow Hedge - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Losses reclassified from AOCI to income
(Loss) Gain Recognized in OCI on Derivatives	$ (5,764)	$ 1,052	$ (11,995)	$ 1,052
(Loss) Gain Reclassified from AOCI to Income (Effective Portion)	(3,038)	(3,037)	(9,113)	(7,846)
Interest rate contracts
Losses reclassified from AOCI to income
(Loss) Gain Recognized in OCI on Derivatives	(2,207)	1,052	(12,670)	1,052
Commodity derivatives
Losses reclassified from AOCI to income
(Loss) Gain Recognized in OCI on Derivatives	(3,557)	0	675	0
Interest and debt expense | Interest rate contracts
Losses reclassified from AOCI to income
(Loss) Gain Reclassified from AOCI to Income (Effective Portion)	(3,038)	(3,037)	(9,113)	(9,112)
Product sales | Commodity derivatives
Losses reclassified from AOCI to income
(Loss) Gain Reclassified from AOCI to Income (Effective Portion)	$ 0	$ 0	$ 0	$ 1,266

FAIR VALUE MEASUREMENTS - Asset

FAIR VALUE MEASUREMENTS - Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Fair value measurements
Fair value	$ 47,234	$ 33,808
Fair Value, Measurements, Recurring | Level 1
Fair value measurements
Fair value	0	(26,219)
Fair Value, Measurements, Recurring | Level 1 | Physical fixed-price derivative contracts
Fair value measurements
Financial assets	0	0
Financial liabilities	0	0
Fair Value, Measurements, Recurring | Level 1 | Physical index derivative contracts
Fair value measurements
Financial assets	0	0
Financial liabilities	0	0
Fair Value, Measurements, Recurring | Level 1 | Futures contracts for refined petroleum products
Fair value measurements
Financial liabilities	0	(26,219)
Fair Value, Measurements, Recurring | Level 1 | Interest rate derivatives
Fair value measurements
Financial assets	0	0
Fair Value, Measurements, Recurring | Level 2
Fair value measurements
Fair value	47,234	60,027
Fair Value, Measurements, Recurring | Level 2 | Physical fixed-price derivative contracts
Fair value measurements
Financial assets	818	1,352
Financial liabilities	(3,746)	(4,267)
Fair Value, Measurements, Recurring | Level 2 | Physical index derivative contracts
Fair value measurements
Financial assets	226	333
Financial liabilities	(3)	0
Fair Value, Measurements, Recurring | Level 2 | Futures contracts for refined petroleum products
Fair value measurements
Financial liabilities	0	0
Fair Value, Measurements, Recurring | Level 2 | Interest rate derivatives
Fair value measurements
Financial assets	$ 49,939	$ 62,609

FAIR VALUE MEASUREMENTS - Carry

FAIR VALUE MEASUREMENTS - Carrying Value and Fair Value of Debt (Details) - Level 2 - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Carrying Amount
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	$ 4,779,045	$ 4,217,695
Carrying Amount | Fixed-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	3,846,426	3,967,695
Carrying Amount | Variable-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	932,619	250,000
Fair Value
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	4,949,835	4,333,488
Fair Value | Fixed-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	4,016,825	4,083,488
Fair Value | Variable-rate debt
Fair Value And Carrying Value By Balance Sheet Grouping
Total debt	$ 933,010	$ 250,000

UNIT-BASED COMPENSATION PLANS -

UNIT-BASED COMPENSATION PLANS - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015
LTIP and Option Plan
Share-based Compensation Arrangement by Share-based Payment Award
Compensation expense	$ 8.2	$ 8.9	$ 25.9	$ 23
Long Term Incentive Plan 2013
Share-based Compensation Arrangement by Share-based Payment Award
LP Units, available for issuance (in shares)	2,646,326		2,646,326
Awards granted (in shares)			547,000
Long Term Incentive Plan 2013 | Phantom Stock Units | Employee
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in shares)			316,490
Long Term Incentive Plan 2013 | Phantom Stock Units | Independent directors
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in shares)			18,000
Long Term Incentive Plan 2013 | Performance Shares | Employee
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in shares)			212,062
Long Term Incentive Plan 2009, Deferral Plan
Share-based Compensation Arrangement by Share-based Payment Award
Compensation awards deferred					$ 4.4	$ 3.1
Long Term Incentive Plan 2009, Deferral Plan | Phantom Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Awards granted (in shares)			145,138		139,526

UNIT-BASED COMPENSATION PLANS51

UNIT-BASED COMPENSATION PLANS - LTIP Activity for the Period (Details) - Long Term Incentive Plan 2013 $ / shares in Units, shares in Thousands, $ in Millions	9 Months Ended
	Sep. 30, 2017USD ($)$ / sharesshares
Number of LP Units
Beginning Balance (in shares) | shares	1,296
Granted (in shares) | shares	547
Performance adjustment (in shares) | shares	32
Vested (in shares) | shares	(333)
Forfeited (in shares) | shares	(32)
Ending Balance (in shares) | shares	1,510
Weighted Average Grant Date Fair Value per LP Unit
Beginning Balance (in dollars per share) | $ / shares	$ 63.54
Granted (in dollars per share) | $ / shares	69.93
Performance adjustment (in dollars per share) | $ / shares	71.50
Vested (in dollars per share) | $ / shares	70.30
Forfeited (in dollars per share) | $ / shares	64.48
Ending Balance (in dollars per share) | $ / shares	$ 64.47
Additional disclosures
Compensation expense expected to be recognized | $	$ 40.5
Unrecognized compensation cost, weighted average period of recognition	1 year 9 months 22 days

UNIT-BASED COMPENSATION PLANS52

UNIT-BASED COMPENSATION PLANS - Summary of Changes in the Options Outstanding Under the Option Plan (Details) - Option Plan - Limited Partners - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Number of LP Units
Beginning Balance (in units)	10
Exercised (in units)	(10)
Ending Balance (in units)	0		10
Exercisable (in units)	0
Weighted Average Strike Price per LP Unit
Beginning Balance (in dollars per share)	$ 50.36
Exercised (in dollars per share)	0
Ending Balance (in dollars per share)	0		$ 50.36
Exercisable (in dollars per share)	$ 0
Weighted Average Remaining Contractual Term (in years)
Outstanding			1 month 6 days
Aggregate Intrinsic Value
Outstanding	$ 0		$ 151
Exercisable	0
Additional disclosures
Total intrinsic value of options exercised	$ 200	$ 100

PARTNERS' CAPITAL AND DISTRIB53

PARTNERS' CAPITAL AND DISTRIBUTIONS - Narrative (Details) - USD ($) shares in Thousands	Sep. 21, 2017	Mar. 31, 2016	Sep. 30, 2017
Partner's capital and distributions
Limited partner ownership percentage			66.67%
Equity Distribution Agreements
Partner's capital and distributions
LP Units authorized to sell (in shares)		$ 500,000,000
Proceeds from issuance of units			$ 346,000,000
Compensation fees paid			$ 1,900,000
Limited Partners | Equity Distribution Agreements
Partner's capital and distributions
Public offering, LP units issued (in shares)	3,800		6,159

PARTNERS' CAPITAL AND DISTRIB54

PARTNERS' CAPITAL AND DISTRIBUTIONS - Summary of Changes in Outstanding Units (Details) - Limited Partner - shares shares in Thousands	Sep. 21, 2017	Sep. 30, 2017
Summary of Changes in Outstanding Units for the Period
Beginning Balance (in shares)		140,264
Ending Balance (in shares)		146,642
Equity Distribution Agreements
Summary of Changes in Outstanding Units for the Period
Issuance of units through Equity Distribution Agreements (in shares)	3,800	6,159
Option Plan
Summary of Changes in Outstanding Units for the Period
LP Units issued (in shares)		10
Long Term Incentive Plan 2013
Summary of Changes in Outstanding Units for the Period
LP Units issued (in shares)		209

PARTNERS' CAPITAL AND DISTRIB55

PARTNERS' CAPITAL AND DISTRIBUTIONS - Distributions (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 20, 2017	Nov. 03, 2017	Sep. 30, 2017	Sep. 30, 2016
Distributions to unitholders
Actual cash distributions			$ 529,169	$ 469,764
Limited Partners
Distributions to unitholders
Actual cash distributions			$ 531,400	$ 472,100
Distribution per LP unit (in dollars per share)			$ 3.75	$ 3.6
Forecast | Limited Partners
Distributions to unitholders
Actual cash distributions	$ 186,200
Subsequent event | Limited Partners
Distributions to unitholders
Cash distributions declared (in dollars per share)		$ 1.2625

EARNINGS PER UNIT (Details)

EARNINGS PER UNIT (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Earnings Per Share [Abstract]
Net income attributable to Buckeye Partners, L.P.	$ 116,187	$ 156,374	$ 352,485	$ 427,943
Basic:
Weighted average units outstanding - basic (in shares)	142,088	131,113	141,104	130,439
Earnings per unit - basic (in dollars per share)	$ 0.82	$ 1.19	$ 2.50	$ 3.28
Diluted:
Weighted average units outstanding - basic (in shares)	142,088	131,113	141,104	130,439
Dilutive effect of LP Unit options and LTIP awards granted (in shares)	730	827	677	637
Weighted average units outstanding - diluted (in shares)	142,818	131,940	141,781	131,076
Earnings per unit - diluted (in dollars per share)	$ 0.81	$ 1.19	$ 2.49	$ 3.26

BUSINESS SEGMENTS - Narrative (

BUSINESS SEGMENTS - Narrative (Details) $ in Thousands, bbl in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Jan. 31, 2017continentterminalbbl	Sep. 30, 2017USD ($)propane_storage	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)terminalsegmentpropane_storage	Sep. 30, 2016USD ($)
Segment information
Number of business segments | segment				3
Depreciation and amortization | $		$ 65,661	$ 63,472	$ 195,987	$ 188,220
Domestic Pipelines & Terminals
Segment information
Number of terminals operated				3
Global Marine Terminals
Segment information
Number of terminals owned				22
Merchant Services
Segment information
Number of terminals owned				3
Indiana and Illinois | Domestic Pipelines & Terminals
Segment information
Number of underground propane storage caverns | propane_storage		2		2
VTTI B.V.
Segment information
Product storage capacity (in bbl) | bbl	58
Number of terminals	15
Number of continents | continent	5
Buckeye Texas Partners LLC
Segment information
Ownership percentage		100.00%		100.00%
Depreciation and amortization | $		$ 18,100	$ 18,500	$ 54,100	$ 52,500
VTTI B.V.
Segment information
Ownership percentage	50.00%	50.00%		50.00%

BUSINESS SEGMENTS - Revenue by

BUSINESS SEGMENTS - Revenue by Segment (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenue:
Total revenue	$ 922,619	$ 766,605	$ 2,702,093	$ 2,324,321
United States
Revenue:
Total revenue	855,795	683,850	2,474,562	2,072,893
International
Revenue:
Total revenue	66,824	82,755	227,531	251,428
Operating Segments | Domestic Pipelines & Terminals
Revenue:
Total revenue	254,277	265,036	761,438	752,968
Operating Segments | Global Marine Terminals
Revenue:
Total revenue	155,281	170,072	487,613	509,653
Operating Segments | Merchant Services
Revenue:
Total revenue	526,844	344,041	1,498,438	1,103,186
Intersegment
Revenue:
Total revenue	$ (13,783)	$ (12,544)	$ (45,396)	$ (41,486)

BUSINESS SEGMENTS - Adjusted EB

BUSINESS SEGMENTS - Adjusted EBITDA from Continuing Operations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Segment information
Adjusted EBITDA	$ 277,318	$ 271,649	$ 824,018	$ 772,864
Reconciliation of Net Income to Adjusted EBITDA:
Net income	120,224	160,270	362,912	439,746
Less: Net income attributable to noncontrolling interests	(4,037)	(3,896)	(10,427)	(11,803)
Net income attributable to Buckeye Partners, L.P.	116,187	156,374	352,485	427,943
Add: Interest and debt expense	56,561	48,476	168,870	144,093
Income tax expense	448	308	1,709	896
Depreciation and amortization	65,661	63,472	195,987	188,220
Gains on property damage recoveries			(4,621)	(5,700)
Earnings from the equity-method investment in VTTI	(9,232)	(2,901)	(22,710)	(8,459)
Adjusted EBITDA	277,318	271,649	824,018	772,864
Segment Reconciling Items
Reconciliation of Net Income to Adjusted EBITDA:
Non-cash unit-based compensation expense	8,176	8,853	25,756	22,912
Acquisition and transition expense	1,447	309	3,275	479
Hurricane-related costs	1,804	0	4,820	0
Proportionate share of Adjusted EBITDA for the equity-method investment in VTTI	33,430	0	90,848	0
Less: Amortization of unfavorable storage contracts	0	(443)	0	(5,979)
Gains on property damage recoveries	0	(5,700)	(4,621)	(5,700)
Segment Reconciling Items | VTTI B.V.
Reconciliation of Net Income to Adjusted EBITDA:
Earnings from the equity-method investment in VTTI	(6,396)	0	(15,111)	0
Domestic Pipelines & Terminals
Segment information
Adjusted EBITDA	138,880	152,785	413,710	423,245
Reconciliation of Net Income to Adjusted EBITDA:
Adjusted EBITDA	138,880	152,785	413,710	423,245
Global Marine Terminals
Segment information
Adjusted EBITDA	128,696	110,705	391,084	325,710
Reconciliation of Net Income to Adjusted EBITDA:
Adjusted EBITDA	128,696	110,705	391,084	325,710
Global Marine Terminals | VTTI B.V.
Reconciliation of Net Income to Adjusted EBITDA:
Earnings from the equity-method investment in VTTI	(6,396)	0	(15,111)	0
Merchant Services
Segment information
Adjusted EBITDA	9,742	8,159	19,224	23,909
Reconciliation of Net Income to Adjusted EBITDA:
Adjusted EBITDA	$ 9,742	$ 8,159	$ 19,224	$ 23,909

SUPPLEMENTAL CASH FLOW INFORM60

SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest (net of capitalized interest)	$ 161,914	$ 141,140
Cash paid for income taxes	1,359	670
Capitalized interest	3,445	3,142
Capital expenditures incurred but not yet paid	$ 51,000	$ 45,200